Downhole burners for in situ conversion of organic-rich rock formations

ABSTRACT

A method for in situ heating of a selected portion of a targeted organic-rich rock formation such as an oil shale formation is provided. The method includes the steps of providing casing in a wellbore extending to a depth within or below the selected portion of the organic-rich rock formation, and also providing a tubing within the casing. An annular region is formed between the tubing and the surrounding casing. Air or other oxidant and a combustible fuel are injected into the wellbore. Either the air or the combustible fuel is in stoichiometric combustion excess. The method also includes providing hardware in the wellbore so as to cause the air and the combustible fuel to mix and to combust at substantially the depth of the organic-rich rock formation. The hardware may include more than one burner. Insulation may be placed along the tubing adjacent the first burner in order to reduce the heat transfer coefficient within the tubing and to provide a more uniform temperature within the annulus.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application Ser. No. 60/930,308 filed May 15, 2007. That application is titled “Downhole Burners for In Situ Conversion of Organic-Rich Rock Formations,” and is incorporated herein in its entirety by reference.

This application is related to co-pending, concurrently filed, and commonly assigned U.S. patent application Ser. No. 12/148,414 entitled “Downhole Burner Wells For In Situ Conversion of Organic-Rich Rock Formations”, which claims the benefit of U.S. Provisional Patent Application Ser. No. 60/930,311, filed May 15, 2007, the disclosures of which are hereby incorporated herein in their entirety by reference.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to the field of hydrocarbon recovery from subsurface formations. More specifically, the present invention relates to the in situ recovery of hydrocarbon fluids from organic-rich rock formations including, for example, oil shale formations, coal formations and tar sands formations. The present invention also relates to methods for heating a subsurface formation using combustible fuel.

2. Discussion of the Art

Certain geological formations are known to contain an organic matter known as “kerogen.” Kerogen is a solid, carbonaceous material. When kerogen is imbedded in rock formations, the mixture is referred to as oil shale. This is true whether or not the mineral is, in fact, technically shale, that is, a rock formed from compacted clay.

Kerogen is subject to decomposing upon exposure to heat over a period of time. Upon heating, kerogen molecularly decomposes to produce oil, gas, and carbonaceous coke. Small amounts of water may also be generated. The oil, gas and water fluids become mobile within the rock matrix, while the carbonaceous coke remains essentially immobile.

Oil shale formations are found in various areas world-wide, including the United States. Such formations are notably found in Wyoming, Colorado, and Utah. Oil shale formations tend to reside at relatively shallow depths and are often characterized by limited permeability. Some consider oil shale formations to be hydrocarbon deposits which have not yet experienced the years of heat and pressure thought to be required to create conventional oil and gas reserves.

The decomposition rate of kerogen to produce mobile hydrocarbons is temperature dependent. Temperatures generally in excess of 270° C. (518° F.) over the course of many months may be required for substantial conversion. At higher temperatures substantial conversion may occur within shorter times. When kerogen is heated to the necessary temperature, chemical reactions break the larger molecules forming the solid kerogen into smaller molecules of oil and gas. The thermal conversion process is referred to as pyrolysis or retorting.

Attempts have been made for many years to extract oil from oil shale formations. Near-surface oil shales have been mined and retorted at the surface for over a century. In 1862, James Young began processing Scottish oil shales. The industry lasted for about 100 years. Commercial oil shale retorting through surface mining has been conducted in other countries as well such as Australia, Brazil, China, Estonia, France, Russia, South Africa, Spain, and Sweden. However, the practice has been mostly discontinued in recent years because it proved to be uneconomical or because of environmental constraints on spent shale disposal. (See T. F. Yen, and G. V. Chilingarian, “Oil Shale,” Amsterdam, Elsevier, p. 292, the entire disclosure of which is incorporated herein by reference.) Further, surface retorting requires mining of the oil shale, which limits application to very shallow formations.

In the United States, the existence of oil shale deposits in northwestern Colorado has been known since the early 1900's. While research projects have been conducted in this area from time to time, no serious commercial development has been undertaken. Most research on oil shale production has been carried out in the latter half of the 1900's. The majority of this research was on shale oil geology, geochemistry, and retorting in surface facilities.

In 1947, U.S. Pat. No. 2,732,195 issued to Ljungstrom. That patent, entitled “Method of Treating Oil Shale and Recovery of Oil and Other Mineral Products Therefrom,” proposed the application of heat at high temperatures to the oil shale formation in situ. The purpose of such in situ heating was to distill hydrocarbons and produce them to the surface. The '195 Ljungstrom patent is incorporated herein by reference.

Ljungstrom coined the phrase “heat supply channels” to describe bore holes drilled into the formation. The bore holes received an electrical heat conductor which transferred heat to the surrounding oil shale. Thus, the heat supply channels served as early heat injection wells. The electrical heating elements in the heat injection wells were placed within sand or cement or other heat-conductive material to permit the heat injection wells to transmit heat into the surrounding oil shale while preventing the inflow of fluid. According to Ljungstrom, the “aggregate” was heated to between 500° and 1,000° C. in some applications.

Along with the heat injection wells, fluid producing wells were also completed in near proximity to the heat injection wells. As kerogen was pyrolyzed upon heat conduction into the rock matrix, the resulting oil and gas would be recovered through the adjacent production wells.

Ljungstrom applied his approach of thermal conduction from heated wellbores through the Swedish Shale Oil Company. A full scale plant was developed that operated from 1944 into the 1950's. (See G. Salamonsson, “The Ljungstrom In Situ Method for Shale-Oil Recovery,” 2^(nd) Oil Shale and Cannel Coal Conference, v. 2, Glasgow, Scotland, Institute of Petroleum, London, p. 260-280 (1951), the entire disclosure of which is incorporated herein by reference.)

Additional in situ methods have been proposed. These methods generally involve the injection of heat and/or solvent into a subsurface oil shale formation. Heat may be in the form of heated methane (see U.S. Pat. No. 3,241,611 to J. L. Dougan), flue gas, or superheated steam (see U.S. Pat. No. 3,400,762 to D. W. Peacock). Heat may also be in the form of electric resistive heating, dielectric heating, radio frequency (RF) heating (U.S. Pat. No. 4,140,180, assigned to the ITT Research Institute in Chicago, Ill.) or oxidant injection to support in situ combustion. In some instances, artificial permeability has been created in the matrix to aid the movement of pyrolyzed fluids. Permeability generation methods include mining, rubblization, hydraulic fracturing (see U.S. Pat. No. 3,468,376 to M. L. Slusser and U.S. Pat. No. 3,513,914 to J. V. Vogel), explosive fracturing (see U.S. Pat. No. 1,422,204 to W. W. Hoover, et al.), heat fracturing (see U.S. Pat. No. 3,284,281 to R. W. Thomas), and steam fracturing (see U.S. Pat. No. 2,952,450 to H. Purre).

In 1989, U.S. Pat. No. 4,886,118 issued to Shell Oil Company, the entire disclosure of which is incorporated herein by reference. That patent, entitled “Conductively Heating a Subterranean Oil Shale to Create Permeability and Subsequently Produce Oil,” declared that “[c]ontrary to the implications of . . . prior teachings and beliefs . . . the presently described conductive heating process is economically feasible for use even in a substantially impermeable subterranean oil shale.” (col. 6, ln. 50-54). Despite this declaration, it is noted that few, if any, commercial in situ shale oil operations have occurred other than Ljungstrom's enterprise. The '118 patent proposed controlling the rate of heat conduction within the rock surrounding each heat injection well to provide a uniform heat front.

Additional history behind oil shale retorting and shale oil recovery can be found in co-owned patent publication WO 2005/010320 entitled “Methods of Treating a Subterranean Formation to Convert Organic Matter into Producible Hydrocarbons,” and in patent publication WO 2005/045192 entitled “Hydrocarbon Recovery from Impermeable Oil Shales.” The Background and technical disclosures of these two patent publications are incorporated herein by reference.

A need exists for improved processes for the production of shale oil. In addition, a need exists for improved downhole burners for converting kerogen or other solid organic matter in a subsurface formation into hydrocarbon fluids.

SUMMARY OF THE INVENTION

A method for in situ heating of a selected portion of an organic-rich rock formation is provided. In one aspect, the method may include providing casing in a wellbore located at least partially within the organic-rich rock formation. The casing extends to a depth within or below the selected portion of the organic-rich rock formation. The method may further include providing a tubing within the casing. The tubing forms a first annulus between the tubing and the surrounding casing.

The method employs an oxidant and a combustible fuel. The method then further includes setting an amount of stoichiometric combustion excess of either the oxidant or the combustible fuel so as to provide a more uniform temperature profile in the first annulus along the selected portion of the organic-rich rock formation. The oxidant and the combustible fuel are injected into the wellbore, with either the oxidant or the combustible fuel being substantially in the amount of stoichiometric combustion excess.

The method may further include providing hardware in the wellbore so as to cause the oxidant and the combustible fuel to mix and to combust into flue gas. Combustion occurs at a first combustion depth located substantially within the selected portion of the organic-rich rock formation. The flue gas is moved up the first annulus between the tubing and the surrounding casing.

The method may also include providing insulation along at least a portion of the tubing below the first combustion depth. This serves to reduce the heat transfer coefficient between the flue gas in the first annulus and the flue gas within the tubing during circulation of the flue gas up the first annulus.

Also provided herein is an improved heater well for in situ heating of an organic-rich rock formation. The heater well may include a casing in a wellbore located at least partially within the organic-rich rock formation. The casing extends to a depth within or below the organic-rich rock formation and is substantially sealed to the formation. The heater well may further include a tubing within the casing. The tubing defines an annulus between the tubing and the surrounding casing. A first tubular member resides within the tubing and extends to a first depth within the organic-rich rock formation.

The heater well may further include a (1) first burner proximate the bottom end of the first tubular member, and (2) a second tubular member residing within the tubing and extending to a second depth within the organic-rich rock formation, wherein the second depth is lower than the first depth. The heater well may further include a second burner proximate a bottom end of the second tubular member. An insulation layer may be provided on the tubing proximate each of the first depth and second depth. Preferably, thermal power capacities of the first and second burners, spacing between the first and second burners, lengths of the insulation layers, or combinations thereof are specified to create a substantially uniform temperature profile within the casing located along a selected portion of the organic-rich rock formation when the heater well is in operation.

An alternate embodiment for a heater well for in situ heating of an organic-rich rock formation is provided. The heater well may include a casing in a wellbore located at least partially within the organic-rich rock formation. The casing extends to a depth within or below the organic-rich rock formation and is substantially sealed to the formation. The heater well may further include a tubing within the casing. An annulus is defined between the tubing and the surrounding casing.

A first tubular member resides within the tubing. The tubular member extends at least to a first depth within the organic-rich rock formation. A first burner is positioned proximate a bottom end of the first tubular member. A second tubular member resides within the tubing and extends to a second depth within the organic-rich rock formation that is lower than the first depth. A second burner is positioned proximate a bottom end of the second tubular member at a second depth within the formation. An insulation layer is placed on the tubing proximate each of the first depth and the second depth. Preferably, thermal power capacities of the first and second burners, spacing between the first and second burners, lengths of the insulation layers, or combinations thereof are specified to create a substantially uniform temperature profile within the casing located along a selected portion of the organic-rich rock formation when the heater well is in operation.

A method of producing a hydrocarbon fluid is also provided herein. The method may include heating an organic-rich rock formation in situ using a heater well, and producing a hydrocarbon fluid from the organic-rich rock formation In accordance with this embodiment, the hydrocarbon are at least partially generated as a result of pyrolysis of formation hydrocarbons located in the organic-rich rock formation.

In the alternate method, the heater well may include a casing in a wellbore located at least partially within the organic-rich rock formation The casing extends to a depth within or below the organic-rich rock formation and is substantially sealed to the surrounding formation. The heater well may further include a tubing within the casing. An annulus is formed between the tubing and the surrounding casing. The heater well may further include a tubular member residing within the tubing. The tubular member extends at least to the organic-rich rock formation.

The heater well may further include (1) a first burner that is positioned along the tubular member at a first depth within the organic-rich rock formation, and (2) a second burner positioned along the tubular member at a second depth within the formation. The second depth is below the first depth.

An additional alternate embodiment for a method of producing a hydrocarbon fluid is disclosed herein. The additional alternate method may include providing casing in a wellbore located at least partially within an organic-rich rock formation. The casing extends to a depth within or below a selected portion of the formation. The method may further include providing a tubing within the casing. A first annulus is defined between the tubing and the surrounding casing. The method may further include injecting an oxidant and a combustible fuel into the wellbore. Either the oxidant or the combustible fuel is in stoichiometric combustion excess over the other.

The additional alternate method may further include providing hardware in the wellbore. The hardware causes the oxidant and the combustible fuel to mix and to combust into flue gas at a first combustion depth located substantially within the selected portion of the organic-rich rock formation. In this way a selected portion of the organic-rich rock formation is heated. Flue gas is circulated up the first annulus between the tubing and the surrounding casing. This serves to further heat the selected portion of the organic-rich rock formation.

The additional alternate method may further include providing insulation on at least a portion of the tubing. The insulation is located below the first combustion depth, and reduces the heat transfer coefficient between the flue gas in the first annulus and the flue gas within the tubing. The method may further include producing a hydrocarbon fluid from the organic-rich rock formation. The hydrocarbon fluid is at least partially generated as a result of pyrolysis of formation hydrocarbons located in the organic-rich rock formation due to the heating.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the features of the present inventions can be better understood, certain drawings, graphs and flow charts are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications.

FIG. 1 is a cross-sectional isometric view of an illustrative subsurface area. The subsurface area includes an organic-rich rock matrix that defines a subsurface formation.

FIG. 2 is a flow chart demonstrating a general method of in situ thermal recovery of oil and gas from an organic-rich rock formation, in one embodiment.

FIG. 3 is a cross-sectional view of an illustrative oil shale formation that is within or connected to groundwater aquifers and a formation leaching operation.

FIG. 4 is a plan view of an illustrative heater well pattern, around a production well. Two layers of heater wells are shown.

FIG. 5 is a bar chart comparing one ton of Green River oil shale before and after a simulated in situ, retorting process.

FIG. 6 is a process flow diagram of exemplary surface processing facilities for a subsurface formation development.

FIG. 7 is a graph of the weight percent of each carbon number pseudo component occurring from C6 to C38 for laboratory experiments conducted at three different stress levels.

FIG. 8 is a graph of the weight percent ratios of each carbon number pseudo component occurring from C6 to C38 as compared to the C20 pseudo component for laboratory experiments conducted at three different stress levels.

FIG. 9 is a graph of the weight percent ratios of each carbon number pseudo component occurring from C6 to C38 as compared to the C25 pseudo component for laboratory experiments conducted at three different stress levels.

FIG. 10 is a graph of the weight percent ratios of each carbon number pseudo component occurring from C6 to C38 as compared to the C29 pseudo component for laboratory experiments conducted at three different stress levels.

FIG. 11 is a graph of the weight percent of normal alkane hydrocarbon compounds occurring from normal-C6 to normal-C38 for laboratory experiments conducted at three different stress levels.

FIG. 12 is a graph of the weight percent of normal alkane hydrocarbon compounds occurring from normal-C6 to normal-C38 as compared to the normal-C20 hydrocarbon compound for laboratory experiments conducted at three different stress levels.

FIG. 13 is a graph of the weight percent of normal alkane hydrocarbon compounds occurring from normal-C6 to normal-C38 as compared to the normal-C25 hydrocarbon compound for laboratory experiments conducted at three different stress levels.

FIG. 14 is a graph of the weight percent of normal alkane hydrocarbon compounds occurring from normal-C6 to normal-C38 as compared to the normal-C29 hydrocarbon compound for laboratory experiments conducted at three different stress levels.

FIG. 15 is a graph of the weight ratio of normal alkane hydrocarbon compounds to pseudo components for each carbon number from C6 to C38 for laboratory experiments conducted at three different stress levels.

FIG. 16 is a bar graph showing the concentration, in molar percentage, of the hydrocarbon species present in the gas samples taken from duplicate laboratory experiments conducted at three different stress levels.

FIG. 17 is an exemplary view of the gold tube apparatus used in the unstressed Parr heating test described below in Example 1.

FIG. 18 is a cross-sectional view of the Parr vessel used in Examples 1-5, described below.

FIG. 19 is gas chromatogram of gas sampled from Example 1.

FIG. 20 is a whole oil gas chromatogram of liquid sampled from Example 1.

FIG. 21 is an exemplary view of a Berea cylinder, Berea plugs, and an oil shale core specimen as used in Examples 2-5.

FIG. 22 is an exemplary view of the mini load frame and sample assembly used in Examples 2-5.

FIG. 23 is gas chromatogram of gas sampled from Example 2.

FIG. 24 is gas chromatogram of gas sampled from Example 3.

FIG. 25 is a whole oil gas chromatogram of liquid sampled from Example 3.

FIG. 26 is gas chromatogram of gas sampled from Example 4.

FIG. 27 is a whole oil gas chromatogram of liquid sampled from Example 4.

FIG. 28 is gas chromatogram of gas sampled from Example 5.

FIG. 29 is a cross-sectional view of a heater well, in one embodiment. Here, a plurality of burners are disposed in a wellbore. The wellbore is completed through an organic-rich rock formation.

FIG. 30 is a top view of the wellbore of FIG. 29.

FIG. 31 is a side view of one of the burners from the heater well of FIG. 29. A cowl to contain a flame and to control oxidant mixing is seen disposed immediately below the burner.

FIG. 32 is a cross-sectional view of a heater well in an alternate embodiment. A plurality of burners is again disposed in a wellbore. The wellbore is completed through an organic-rich rock formation.

FIG. 33 is a side view of one of the burners from the heater well of FIG. 32. A cowl is seen disposed immediately below the burner.

FIG. 34A is a graph charting depth in a wellbore versus temperature. The depth in the wellbore is charted relative to the location of a burner downhole. In this wellbore, a single burner is used, and insulation is placed along the inner tubing below the burner. The average temperatures of the downward flow of gases within the tubing and in the upward flow of flue gas outside of the tubing are compared.

FIG. 34B is a graph charting depth in a wellbore versus temperature. The depth in the wellbore is charted relative to the location of a burner downhole. In this wellbore, a single burner is used, but no insulation is provided along the inner tubing. The average temperatures of the downward flow of gases within the tubing and in the upward flow of flue gas outside of the tubing are compared.

FIG. 34C is a graph charting depth in a wellbore versus temperature. The depth in the wellbore is charted relative to the location of a burner downhole. In this wellbore, a single burner is used, and insulation is placed along the inner tubing below the burner. A lower injection rate is used for the air as compared to the wellbores of FIGS. 34A and 34B. The average temperatures of the downward flow of gases within the tubing and in the upward flow of flue gas outside of the tubing are compared.

FIG. 34D is a graph charting depth in a wellbore versus temperature. The depth in the wellbore, is charted relative to the location of a burner downhole. In this wellbore, three burners are used, and insulation is placed along the inner tubing below the uppermost burner. The average temperatures of the downward flow of gases within the tubing and in the upward flow of flue gas outside of the tubing are compared.

FIG. 35 is a side view of a portion of a wellbore having a downhole burner therein. The wellbore is shown to demonstrate the utility of the graph of FIG. 34A.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS Definitions

As used herein, the term “hydrocarbon(s)” refers to organic material with molecular structures containing carbon bonded to hydrogen. Hydrocarbons may also include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions or at ambient conditions (15° C. and 1 atm pressure). Hydrocarbon fluids may include, for example, oil, natural gas, coal bed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, the terms “produced fluids” and “production fluids” refer to liquids and/or gases removed from a subsurface formation, including, for example, an organic-rich rock formation. Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids. Production fluids may include, but are not limited to, pyrolyzed shale oil, synthesis gas, a pyrolysis product of coal, carbon dioxide, hydrogen sulfide and water (including steam). Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids.

As used herein, the term “condensable hydrocarbons” means those hydrocarbons that condense at 25° C. and one atmosphere absolute pressure. Condensable hydrocarbons may include a mixture of hydrocarbons having carbon numbers greater than 4.

As used herein, the term “non-condensable hydrocarbons” means those hydrocarbons that do not condense at 25° C. and one atmosphere absolute pressure. Non-condensable hydrocarbons may include hydrocarbons having carbon numbers less than 5.

As used herein, the term “heavy hydrocarbons” refers to hydrocarbon fluids that are highly viscous at ambient conditions (15° C. and 1 atm pressure). Heavy hydrocarbons may include highly viscous hydrocarbon fluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, as well as smaller concentrations of sulfur, oxygen, and nitrogen. Additional elements may also be present in heavy hydrocarbons in trace amounts. Heavy hydrocarbons may be classified by API gravity. Heavy hydrocarbons generally have an API gravity below about 20 degrees. Heavy oil, for example, generally has an API gravity of about 10-20 degrees, whereas tar generally has an API gravity below about 10 degrees. The viscosity of heavy hydrocarbons is generally greater than about 100 centipoise at 15° C.

As used herein, the term “solid hydrocarbons” refers to any hydrocarbon material that is found naturally in substantially solid form at formation conditions. Non-limiting examples include kerogen, coal, shungites, asphaltites, and natural mineral waxes.

As used herein, the term “formation hydrocarbons” refers to both heavy hydrocarbons and solid hydrocarbons that are contained in an organic-rich rock formation. Formation hydrocarbons may be, but are not limited to, kerogen, oil shale, coal, bitumen, tar, natural mineral waxes, and asphaltites.

As used herein, the term “tar” refers to a viscous hydrocarbon that generally has a viscosity greater than about 10,000 centipoise at 15° C. The specific gravity of tar generally is greater than 1.000. Tar may have an API gravity less than 10 degrees. “Tar sands” refers to a formation that has tar in it.

As used herein, the term “kerogen” refers to a solid, insoluble hydrocarbon that principally contains carbon, hydrogen, nitrogen, oxygen, and sulfur. Oil shale contains kerogen.

As used herein, the term “bitumen” refers to a non-crystalline solid or viscous hydrocarbon material that is substantially soluble in carbon disulfide.

As used herein, the term “oil” refers to a hydrocarbon fluid containing a mixture of condensable hydrocarbons.

As used herein, the term “subsurface” refers to geologic strata occurring below the earth's surface.

As used herein, the term “hydrocarbon-rich formation” refers to any formation that contains more than trace amounts of hydrocarbons. For example, a hydrocarbon-rich formation may include portions that contain hydrocarbons at a level of greater than 5 volume percent. The hydrocarbons located in a hydrocarbon-rich formation may include, for example, oil, natural gas, heavy hydrocarbons, and solid hydrocarbons.

As used herein, the term “organic-rich rock” refers to any rock matrix holding solid hydrocarbons and/or heavy hydrocarbons. Rock matrices may include, but are not limited to, sedimentary rocks, shales, siltstones, sands, silicilytes, carbonates, and diatomites.

As used herein, the term “formation” refers to any finite subsurface region. The formation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any subsurface geologic formation. An “overburden” and/or an “underburden” is geological material above or below the formation of interest. An overburden or underburden may include one or more different types of substantially impermeable materials. For example, overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate (i.e., an impermeable carbonate without hydrocarbons). An overburden and/or an underburden may include a hydrocarbon-containing layer that is relatively impermeable. In some cases, the overburden and/or underburden may be permeable.

As used herein, the term “organic-rich rock formation” refers to any formation containing organic-rich rock. Organic-rich rock formations include, for example, oil shale formations, coal formations, and tar sands formations.

As used herein, the term “pyrolysis” refers to the breaking of chemical bonds through the application of heat. For example, pyrolysis may include transforming a compound into one or more other substances by heat alone or by heat in combination with an oxidant. Pyrolysis may include modifying the nature of the compound by addition of hydrogen atoms which may be obtained from molecular hydrogen, water, carbon dioxide, or carbon monoxide. Heat may be transferred to a section of the formation to cause pyrolysis.

As used herein, the term “water-soluble minerals” refers to minerals that are soluble in water. Water-soluble minerals include, for example, nahcolite (sodium bicarbonate), soda ash (sodium carbonate), dawsonite (NaAl(CO₃)(OH)₂), or combinations thereof. Substantial solubility may require heated water and/or a non-neutral pH solution.

As used herein, the term “formation water-soluble minerals” refers to water-soluble minerals that are found naturally in a formation.

As used herein, the term “migratory contaminant species” refers to species that are soluble or moveable in water or an aqueous fluid, and are considered to be potentially harmful or of concern to human health or the environment. Migratory contaminant species may include inorganic and organic contaminants. Organic contaminants may include saturated hydrocarbons, aromatic hydrocarbons, and oxygenated hydrocarbons. Inorganic contaminants may include metal contaminants, and ionic contaminants of various types that may significantly alter pH or the formation fluid chemistry. Aromatic hydrocarbons may include, for example, benzene, toluene, xylene, ethylbenzene, and tri-methylbenzene, and various types of polyaromatic hydrocarbons such as anthracenes, naphthalenes, chrysenes and pyrenes. Oxygenated hydrocarbons may include, for example, alcohols, ketones, phenols, and organic acids such as carboxylic acid. Metal contaminants may include, for example, arsenic, boron, chromium, cobalt, molybdenum, mercury, selenium, lead, vanadium, nickel or zinc. Ionic contaminants include, for example, sulfides, sulfates, chlorides, fluorides, ammonia, nitrates, calcium, iron, magnesium, potassium, lithium, boron, and strontium.

As used herein, the term “sequestration” refers to the storing of a fluid that is a by-product of a process rather than discharging the fluid to the atmosphere or open environment.

As used herein, the term “subsidence” refers to a downward movement of a surface relative to an initial elevation of the surface.

As used herein, the term “thickness” of a layer refers to the distance between the upper and lower boundaries of a cross section of a layer, wherein the distance is measured normal to the average tilt of the cross section.

As used herein, the term “thermal fracture” refers to fractures created in a formation caused directly or indirectly by expansion or contraction of a portion of the formation and/or fluids within the formation, which in turn is caused by increasing/decreasing the temperature of the formation and/or fluids within the formation, and/or by increasing/decreasing a pressure of fluids within the formation due to heating. Thermal fractures may propagate into or form in neighboring regions significantly cooler than the heated zone.

As used herein, the term “hydraulic fracture” refers to a fracture at least partially propagated into a formation, wherein the fracture is created through injection of pressurized fluids into the formation. The fracture may be artificially held open by injection of a proppant material. Hydraulic fractures may be substantially horizontal in orientation, substantially vertical in orientation, or oriented along any other plane.

As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shapes (e.g., circles, ovals, squares, rectangles, triangles, slits, or other regular or irregular shapes). As used herein, the term “well”, when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”

As used herein, the term “cowl” means a tubular body of any material or construction having perforations or vents therein.

As used herein, the term “targeted organic-rich rock formation” means a portion of an organic-rich rock formation that has been chosen for in situ heating. The chosen portion may be defined according to a given depth or range of depths, a given horizontal distance, or both.

As used herein with respect to temperature and downhole burners, the term “uniform temperature” means that the temperature remains within a desired temperature range over a selected portion of an organic-rich rock formation.

Description of Specific Embodiments

The inventions are described herein in connection with certain specific embodiments. However, to the extent that the following detailed description is specific to a particular embodiment or a particular use, such is intended to be illustrative only and is not to be construed as limiting the scope of the invention.

FIG. 1 presents a perspective view of an illustrative oil shale development area 10. A surface 12 of the development area 10 is indicated. Below the surface is an organic-rich rock formation 16. The illustrative subsurface formation 16 contains formation hydrocarbons (such as, for example, kerogen) and possibly valuable water-soluble minerals (such as, for example, nahcolite). It is understood that the representative formation 16 may be any organic-rich rock formation, including a rock matrix containing coal or tar sands, for example. In addition, the rock matrix making up the formation 16 may be permeable, semi-permeable or non-permeable. The present inventions are particularly advantageous in oil shale development areas initially having very limited or effectively no fluid permeability.

In order to access formation 16 and recover natural resources therefrom, a plurality of wellbores is formed. Wellbores are shown at 14 in FIG. 1. The representative wellbores 14 are essentially vertical in orientation relative to the surface 12. However, it is understood that some or all of the wellbores 14 could deviate into an obtuse or even horizontal orientation. In the arrangement of FIG. 1, each of the wellbores 14 is completed in the oil shale formation 16. The completions may be either open or cased hole. The well completions may also include propped or unpropped hydraulic fractures emanating therefrom.

In the view of FIG. 1, only seven wellbores 14 are shown. However, it is understood that in an oil shale development project, numerous additional wellbores 14 will most likely be drilled. The wellbores 14 may be located in relatively close proximity, being from 10 feet to up to 300 feet in separation. In some embodiments, a well spacing of 15 to 25 feet is provided. Typically, the wellbores 14 are also completed at shallow depths, being from 200 to 5,000 feet at total depth. In some embodiments the oil shale formation targeted for in situ retorting is at a depth greater than 200 feet below the surface or alternatively 400 feet below the surface. Alternatively, conversion and production of a oil shale formation occurs at depths between 500 and 2,500 feet.

The wellbores 14 will be selected for certain functions and may be designated as heat injection wells, water injection wells, oil production wells and/or water-soluble mineral solution production wells. In one aspect, the wellbores 14 are dimensioned to serve two, three, or all four of these purposes. Suitable tools and equipment may be sequentially run into and removed from the wellbores 14 to serve the various purposes.

A fluid processing facility 17 is also shown schematically. The fluid processing facility 17 is equipped to receive fluids produced from the organic-rich rock formation 16 through one or more pipelines or flow lines 18. The fluid processing facility 17 may include equipment suitable for receiving and separating oil, gas, and water produced from the heated formation. The fluid processing facility 17 may further include equipment for separating out dissolved water-soluble minerals and/or migratory contaminant species, including, for example, dissolved organic contaminants, metal contaminants, or ionic contaminants in the produced water recovered from the organic-rich rock formation 16. The contaminants may include, for example, aromatic hydrocarbons such as benzene, toluene, xylene, and tri-methylbenzene. The contaminants may also include polyaromatic hydrocarbons such as anthracene, naphthalene, chrysene and pyrene. Metal contaminants may include species containing arsenic, boron, chromium, mercury, selenium, lead, vanadium, nickel, cobalt, molybdenum, or zinc. Ionic contaminant species may include, for example, sulfates, chlorides, fluorides, lithium, potassium, aluminum, ammonia, and nitrates.

In order to recover oil, gas, and sodium (or other) water-soluble minerals, a series of steps may be undertaken. FIG. 2 presents a flow chart demonstrating a method of in situ thermal recovery of oil and gas from an organic-rich rock formation 100, in one embodiment. It is understood that the order of some of the steps from FIG. 2 may be changed, and that the sequence of steps is merely for illustration.

First, the oil shale (or other organic-rich rock) formation 16 is identified within the development area 10. This step is shown in box 110. Optionally, the oil shale formation may contain nahcolite or other sodium minerals. The targeted development area within the oil shale formation may be identified by measuring or modeling the depth, thickness and organic richness of the oil shale as well as evaluating the position of the organic-rich rock formation relative to other rock types, structural features (e.g. faults, anticlines or synclines), or hydrogeological units (i.e. aquifers). This is accomplished by creating and interpreting maps and/or models of depth, thickness, organic richness and other data from available tests and sources. This may involve performing geological surface surveys, studying outcrops, performing seismic surveys, and/or drilling boreholes to obtain core samples from subsurface rock. Rock samples may be analyzed to assess kerogen content and hydrocarbon fluid generating capability.

The kerogen content of the organic-rich rock formation may be ascertained from outcrop or core samples using a variety of data. Such data may include organic carbon content, hydrogen index, and modified Fischer assay analyses. Subsurface permeability may also be assessed via rock samples, outcrops, or studies of ground water flow. Furthermore the connectivity of the development area to ground water sources may be assessed.

Next, a plurality of wellbores 14 is formed across the targeted development area 10. This step is shown schematically in box 115. The purposes of the wellbores 14 are set forth above and need not be repeated. However, it is noted that for purposes of the wellbore formation step of box 115, only a portion of the wells need be completed initially. For instance, at the beginning of the project heat injection wells are needed, while a majority of the hydrocarbon production wells are not yet needed. Production wells may be brought in once conversion begins, such as after 4 to 12 months of heating.

It is understood that petroleum engineers will develop a strategy for the best depth and arrangement for the wellbores 14, depending upon anticipated reservoir characteristics, economic constraints, and work scheduling constraints. In addition, engineering staff will determine what wellbores 14 shall be used for initial formation 16 heating. This selection step is represented by box 120.

Concerning heat injection wells, there are various methods for applying heat to the organic-rich rock formation 16. The present methods are not limited to the heating technique employed unless specifically so stated in the claims. The heating step is represented generally by box 130. Preferably, for in situ processes the heating of a production zone takes place over a period of months, or even four or more years.

The formation 16 is heated to a temperature sufficient to pyrolyze at least a portion of the oil shale in order to convert the kerogen to hydrocarbon fluids. The bulk of the target zone of the formation may be heated to between 270° C. to 800° C. Alternatively, the targeted volume of the organic-rich formation is heated to at least 350° C. to create production fluids. The conversion step is represented in FIG. 2 by box 135. The resulting liquids and hydrocarbon gases may be refined into products which resemble common commercial petroleum products. Such liquid products include transportation fuels such as diesel, jet fuel and naphtha. Generated gases include light alkanes, light alkenes, H₂, CO₂, CO, and NH₃.

Conversion of the oil shale will create permeability in the oil shale section in rocks that were originally impermeable. Preferably, the heating and conversion processes of boxes 130 and 135, occur over a lengthy period of time. In one aspect, the heating period is from three months to four or more years. Also as an optional part of box 135, the formation 16 may be heated to a temperature sufficient to convert at least a portion of nahcolite, if present, to soda ash. Heat applied to mature the oil shale and recover oil and gas will also convert nahcolite to sodium carbonate (soda ash), a related sodium mineral. The process of converting nahcolite (sodium bicarbonate) to soda ash (sodium carbonate) is described herein.

In connection with the heating step 130, the rock formation 16 may optionally be fractured to aid heat transfer or later hydrocarbon fluid production. The optional fracturing step is shown in box 125. Fracturing may be accomplished by creating thermal fractures within the formation through application of heat. By heating the organic-rich rock and transforming the kerogen to oil and gas, the permeability is increased via thermal fracture formation and subsequent production of a portion of the hydrocarbon fluids generated from the kerogen. Alternatively, a process known as hydraulic fracturing may be used. Hydraulic fracturing is a process known in the art of oil and gas recovery where a fracture fluid is pressurized within the wellbore above the fracture pressure of the formation, thus developing fracture planes within the formation to relieve the pressure generated within the wellbore. Hydraulic fractures may be used to create additional permeability in portions of the formation and/or be used to provide a planar source for heating. The WO 2005/010320 patent publication incorporated above describes one use of hydraulic fracturing.

As part of the hydrocarbon fluid production process 100, certain wells 14 may be designated as oil and gas production wells. This step is depicted by box 140. Oil and gas production might not be initiated until it is determined that the kerogen has been sufficiently retorted to allow maximum recovery of oil and gas from the formation 16. In some instances, dedicated production wells are not drilled until after heat injection wells (box 130) have been in operation for a period of several weeks or months. Thus, box 140 may include the formation of additional wellbores 14. In other instances, selected heater wells are converted to production wells.

After certain wellbores 14 have been designated as oil and gas production wells, oil and/or gas is produced from the wellbores 14. The oil and/or gas production process is shown at box 145. At this stage (box 145), any water-soluble minerals, such as nahcolite and converted soda ash may remain substantially trapped in the rock formation 16 as finely disseminated crystals or nodules within the oil shale beds, and are not produced. However, some nahcolite and/or soda ash may be dissolved in the water created during heat conversion (box 135) within the formation.

Box 150 presents an optional next step in the oil and gas recovery method 100. Here, certain wellbores 14 are designated as water or aqueous fluid injection wells. Aqueous fluids are solutions of water with other species. The water may constitute “brine,” and may include dissolved inorganic salts of chloride, sulfates and carbonates of Group I and II elements of The Periodic Table of Elements. Organic salts can also be present in the aqueous fluid. The water may alternatively be fresh water containing other species. The other species may be present to alter the pH. Alternatively, the other species may reflect the availability of brackish water not saturated in the species wished to be leached from the subsurface. Preferably, the water injection wells are selected from some or all of the wellbores used for heat injection or for oil and/or gas production. However, the scope of the step of box 150 may include the drilling of yet additional wellbores 14 for use as dedicated water injection wells. In this respect, it may be desirable to complete water injection wells along a periphery of the development area 10 in order to create a boundary of high pressure.

Next, optionally water or an aqueous fluid is injected through the water injection wells and into the oil shale formation 16. This step is shown at box 155. The water may be in the form of steam or pressurized hot water. Alternatively the injected water may be cool and becomes heated as it contacts the previously heated formation. The injection process may further induce fracturing. This process may create fingered caverns and brecciated zones in the nahcolite-bearing intervals some distance, for example up to 200 feet out, from the water injection wellbores. In one aspect, a gas cap, such as nitrogen, may be maintained at the top of each “cavern” to prevent vertical growth.

Along with the designation of certain wellbores 14 as water injection wells, the design engineers may also designate certain wellbores 14 as water or water-soluble mineral solution production wells. This step is shown in box 160. These wells may be the same as wells used to previously produce hydrocarbons or inject heat. These recovery wells may be used to produce an aqueous solution of dissolved water-soluble minerals and other species, including, for example, migratory contaminant species. For example, the solution may be one primarily of dissolved soda ash. This step is shown in box 165. Alternatively, single wellbores may be used to both inject water and then to recover a sodium mineral solution. Thus, box 165 includes the option of using the same wellbores 14 for both water injection and solution production (Box 165).

Temporary control of the migration of the migratory contaminant species, especially during the pyrolysis process, can be obtained via placement of the injection and production wells 14 such that fluid flow out of the heated zone is minimized. Typically, this involves placing injection wells at the periphery of the heated zone so as to cause pressure gradients which prevent flow inside the heated zone from leaving the zone.

FIG. 3 is a cross-sectional view of an illustrative oil shale formation that is within or connected to ground water aquifers and a formation leaching operation. Four separate oil shale formation zones are depicted (23, 24, 25 and 26) within the oil shale formation. The water aquifers are below the ground surface 27, and are categorized as an upper aquifer 20 and a lower aquifer 22. Intermediate the upper and lower aquifers is an aquitard 21. It can be seen that certain zones of the formation are both aquifers or aquitards and oil shale zones. A plurality of wells (28, 29, 30 and 31) is shown traversing vertically downward through the aquifers. One of the wells is serving as a water injection well 31, while another is serving as a water production well 30. In this way, water is circulated 32 through at least the lower aquifer 22.

FIG. 3 shows diagrammatically water circulating 32 through an oil shale volume that was heated 33, that resides within or is connected to an aquifer 22, and from which hydrocarbon fluids were previously recovered. Introduction of water via the water injection well 31 forces water into the previously heated oil shale 33 so that water-soluble minerals and migratory contaminants species are swept to the water production well 30. The water may then be processed in a facility 34 wherein the water-soluble minerals (e.g. nahcolite or soda ash) and the migratory contaminants may be substantially removed from the water stream. Water is then reinjected into the oil shale volume 33 and the formation leaching is repeated. This leaching with water is intended to continue until levels of migratory contaminant species are at environmentally acceptable levels within the previously heated oil shale zone 33. This may require 1 cycle, 2 cycles, 5 cycles 10 cycles or more cycles of formation leaching, where a single cycle indicates injection and production of approximately one pore volume of water. It is understood that there may be numerous water injection and water production wells in an actual oil shale development. Moreover, the system may include monitoring wells (28 and 29) which can be utilized during the oil shale heating phase, the shale oil production phase, the leaching phase, or during any combination of these phases to monitor for migratory contaminant species and/or water-soluble minerals.

In some fields, formation hydrocarbons, such as oil shale, may exist in more than one subsurface formation. In some instances, the organic-rich rock formations may be separated by rock layers that are hydrocarbon-free or that otherwise have little or no commercial value. Therefore, it may be desirable for the operator of a field under hydrocarbon development to undertake an analysis as to which of the subsurface, organic-rich rock formations to target or in which order they should be developed.

The organic-rich rock formation may be selected for development based on various factors. One such factor is the thickness of the hydrocarbon containing layer within the formation. Greater pay zone thickness may indicate a greater potential volumetric production of hydrocarbon fluids. Each of the hydrocarbon containing layers may have a thickness that varies depending on, for example, conditions under which the formation hydrocarbon containing layer was formed. Therefore, an organic-rich rock formation will typically be selected for treatment if that formation includes at least one formation hydrocarbon-containing layer having a thickness sufficient for economical production of produced fluids.

An organic-rich rock formation may also be chosen if the thickness of several layers that are closely spaced together is sufficient for economical production of produced fluids. For example, an in situ conversion process for formation hydrocarbons may include selecting and treating a layer within an organic-rich rock formation having a thickness of greater than about 5 meters, 10 meters, 50 meters, or even 100 meters. In this manner, heat losses (as a fraction of total injected heat) to layers formed above and below an organic-rich rock formation may be less than such heat losses from a thin layer of formation hydrocarbons. A process as described herein, however, may also include selecting and treating layers that may include layers substantially free of formation hydrocarbons or thin layers of formation hydrocarbons.

The richness of one or more organic-rich rock formations may also be considered. Richness may depend on many factors including the conditions under which the formation hydrocarbon containing layer was formed, an amount of formation hydrocarbons in the layer, and/or a composition of formation hydrocarbons in the layer. A thin and rich formation hydrocarbon layer may be able to produce significantly more valuable hydrocarbons than a much thicker, less rich formation hydrocarbon layer. Of course, producing hydrocarbons from a formation that is both thick and rich is desirable.

The kerogen content of an organic-rich rock formation may be ascertained from outcrop or core samples using a variety of data. Such data may include organic carbon content, hydrogen index, and modified Fischer assay analyses. The Fischer Assay is a standard method which involves heating a sample of a formation hydrocarbon containing layer to approximately 500° C. in one hour, collecting fluids produced from the heated sample, and quantifying the amount of fluids produced.

Subsurface formation permeability may also be assessed via rock samples, outcrops, or studies of ground water flow. Furthermore the connectivity of the development area to ground water sources may be assessed. Thus, an organic-rich rock formation may be chosen for development based on the permeability or porosity of the formation matrix even if the thickness of the formation is relatively thin.

Other factors known to petroleum engineers may be taken into consideration when selecting a formation for development. Such factors include depth of the perceived pay zone, stratigraphic proximity of fresh ground water to kerogen-containing zones, continuity of thickness, and other factors. For instance, the assessed fluid production content within a formation will also effect eventual volumetric production.

In producing hydrocarbon fluids from an oil shale field, it may be desirable to control the migration of pyrolyzed fluids. In some instances, this includes the use of injection wells, particularly around the periphery of the field. Such wells may inject water, steam, CO₂, heated methane, or other fluids to drive cracked kerogen fluids inwardly towards production wells. In some embodiments, physical barriers may be placed around the area of the organic-rich rock formation under development. One example of a physical barrier involves the creation of freeze walls. Freeze walls are formed by circulating refrigerant through peripheral wells to substantially reduce the temperature of the rock formation. This, in turn, prevents the pyrolyzation of kerogen present at the periphery of the field and the outward migration of oil and gas. Freeze walls will also cause native water in the formation along the periphery to freeze.

The use of subsurface freezing to stabilize poorly consolidated soils or to provide a barrier to fluid flow is known in the art. Shell Exploration and Production Company has discussed the use of freeze walls for oil shale production in several patents, including U.S. Pat. No. 6,880,633 and U.S. Pat. No. 7,032,660. Shell's '660 patent uses subsurface freezing to protect against groundwater flow and groundwater contamination during in situ shale oil production. Additional patents that disclose the use of so-called freeze walls are U.S. Pat. No. 3,528,252, U.S. Pat. No. 3,943,722, U.S. Pat. No. 3,729,965, U.S. Pat. No. 4,358,222, U.S. Pat. No. 4,607,488, and WO Pat. No. 98996480.

As noted above, several different types of wells may be used in the development of an organic-rich rock formation, including, for example, an oil shale field. For example, the heating of the organic-rich rock formation may be accomplished through the use of heater wells. The heater wells may include, for example, electrical resistance heating elements. The production of hydrocarbon fluids from the formation may be accomplished through the use of wells completed for the production of fluids. The injection of an aqueous fluid may be accomplished through the use of injection wells. Finally, the production of an aqueous solution may be accomplished through use of solution production wells.

The different wells listed above may be used for more than one purpose. Stated another way, wells initially completed for one purpose may later be used for another purpose, thereby lowering project costs and/or decreasing the time required to perform certain tasks. For example, one or more of the production wells may also be used as injection wells for later injecting water into the organic-rich rock formation. Alternatively, one or more of the production wells may also be used as solution production wells for later producing an aqueous solution from the organic-rich rock formation.

In other aspects, production wells (and in some circumstances heater wells) may initially be used as dewatering wells (e.g., before heating is begun and/or when heating is initially started). In addition, in some circumstances dewatering wells can later be used as production wells (and in some circumstances heater wells). As such, the dewatering wells may be placed and/or designed so that such wells can be later used as production wells and/or heater wells. The heater wells may be placed and/or designed so that such wells can be later used as production wells and/or dewatering wells. The production wells may be placed and/or designed so that such wells can be later used as dewatering wells and/or heater wells. Similarly, injection wells may be wells that initially were used for other purposes (e.g., heating, production, dewatering, monitoring, etc.), and injection wells may later be used for other purposes. Similarly, monitoring wells may be wells that initially were used for other purposes (e.g., heating, production, dewatering, injection, etc.). Finally, monitoring wells may later be used for other purposes such as water production.

The wellbores for the various wells may be located in relatively close proximity, being from 10 feet to up to 300 feet in separation. Alternatively, the wellbores may be spaced from 30 to 200 feet, or 50 to 100 feet. Typically, the wellbores are also completed at shallow depths, being from 200 to 5,000 feet at total depth. Alternatively, the wellbores may be completed at depths from 1,000 to 4,000 feet, or 1,500 to 3,500 feet. In some embodiments, the oil shale formation targeted for in situ retorting is at a depth greater than 200 feet below the surface. In alternative embodiments, the oil shale formation targeted for in situ retorting is at a depth greater than 500, 1,000, or 1,500 feet below the surface. In alternative embodiments, the oil shale formation targeted for in situ retorting is at a depth between 200 and 5,000 feet, alternatively between 1,000 and 4,000 feet, 1,200 and 3,700 feet, or 1,500 and 3,500 feet below the surface.

It is desirable to arrange the various wells for an oil shale field in a pre-planned pattern. For instance, heater wells may be arranged in a variety of patterns including, but not limited to triangles, squares, hexagons, and other polygons. The pattern may include a regular polygon to promote uniform heating through at least the portion of the formation in which the heater wells are placed. The pattern may also be a line drive pattern. A line drive pattern generally includes a first linear array of heater wells, a second linear array of heater wells, and a production well or a linear array of production wells between the first and second linear array of heater wells. Interspersed among the heater wells are typically one or more production wells. The injection wells may likewise be disposed within a repetitive pattern of units, which may be similar to or different from that used for the heater wells.

One method to reduce the number of wells is to use a single well as both a heater well and a production well. Reduction of the number of wells by using single wells for sequential purposes can reduce project costs. One or more monitoring wells may be disposed at selected points in the field. The monitoring wells may be configured with one or more devices that measure a temperature, a pressure, and/or a property of a fluid in the wellbore. In some instances, a heater well may also serve as a monitoring well, or otherwise be instrumented.

Another method for reducing the number of heater wells is to use well patterns. Regular patterns of heater wells equidistantly spaced from a production well may be used. The patterns may form equilateral triangular arrays, hexagonal arrays, or other array patterns. The arrays of heater wells may be disposed such that a distance between each heater well is less than about 70 feet (21 meters). A portion of the formation may be heated with heater wells disposed substantially parallel to a boundary of the hydrocarbon formation.

In alternative embodiments, the array of heater wells may be disposed such that a distance between each heater well may be less than about 100 feet, or 50 feet, or 30 feet. Regardless of the arrangement of or distance between the heater wells, in certain embodiments, a ratio of heater wells to production wells disposed within a organic-rich rock formation may be greater than about 5, 8, 10, 20, or more.

In one embodiment, individual production wells are surrounded by at most one layer of heater wells. This may include arrangements such as 5-spot, 7-spot, or 9-spot arrays, with alternating rows of production and heater wells. In another embodiment, two layers of heater wells may surround a production well, but with the heater wells staggered so that a clear pathway exists for the majority of flow away from the further heater wells. Flow and reservoir simulations may be employed to assess the pathways and temperature history of hydrocarbon fluids generated in situ as they migrate from their points of origin to production wells.

FIG. 4 provides a plan view of an illustrative heater well arrangement using more than one layer of heater wells. The heater well arrangement is used in connection with the production of hydrocarbons from a shale oil development area 400. In FIG. 4, the heater well arrangement employs a first layer of heater wells 410, surrounded by a second layer of heater wells 420. The heater wells in the first layer 410 are referenced at 431, while the heater wells in the second layer 420 are referenced at 432.

A production well 440 is shown central to the well layers 410 and 420. It is noted that the heater wells 432 in the second layer 420 of wells are offset from the heater wells 431 in the first layer 410 of wells, relative to the production well 440. The purpose is to provide a flowpath for converted hydrocarbons that minimizes travel near a heater well in the first layer 410 of heater wells. This, in turn, minimizes secondary cracking of hydrocarbons converted from kerogen as hydrocarbons flow from the second layer of wells 420 to the production wells 440.

In the illustrative arrangement of FIG. 4, the first layer 410 and the second layer 420 each defines a 5-spot pattern. However, it is understood that other patterns may be employed, such as 3-spot or 6-spot patterns. In any instance, a plurality of heater wells 431 comprising a first layer of heater wells 410 is placed around a production well 440, with a second plurality of heater wells 432 comprising a second layer of heater wells 420 placed around the first layer 410.

The heater wells in the two layers also may be arranged such that the majority of hydrocarbons generated by heat from each heater well 432 in the second layer 420 are able to migrate to a production well 440 without passing substantially near a heater well 431 in the first layer 410. The heater wells 431, 432 in the two layers 410, 420 further may be arranged such that the majority of hydrocarbons generated by heat from each heater well 432 in the second layer 420 are able to migrate to the production, well 440 without passing through a zone of substantially increasing formation temperature.

Another method for reducing the number of heater wells is to use well patterns that are elongated in a particular direction, particularly in a direction determined to provide the most efficient thermal conductivity. Heat convection may be affected by various factors such as bedding planes and stresses within the formation. For instance, heat convection may be more efficient in the direction perpendicular to the least horizontal principal stress on the formation. In some instanced, heat convection may be more efficient in the direction parallel to the least horizontal principal stress.

In connection with the development of a shale oil field, it may be desirable that the progression of heat through the subsurface in accordance with steps 130 and 135 be uniform. However, for various reasons the heating and maturation of formation hydrocarbons in a subsurface formation may not proceed uniformly despite a regular arrangement of heater and production wells. Heterogeneities in the oil shale properties and formation structure may cause certain local areas to be more or less productive. Moreover, formation fracturing which occurs due to the heating and maturation of the oil shale can lead to an uneven distribution of preferred pathways and, thus, increase flow to certain production wells and reduce flow to others. Uneven fluid maturation may be an undesirable condition since certain subsurface regions may receive more heat energy than necessary where other regions receive less than desired. This, in turn, leads to the uneven flow and recovery of production fluids. Produced oil quality, overall production rate, and/or ultimate recoveries may be reduced.

To detect uneven flow conditions, production and heater wells may be instrumented with sensors. Sensors may include equipment to measure temperature, pressure, flow rates, and/or compositional information. Data from these sensors can be processed via simple rules or input to detailed simulations to reach decisions on how to adjust heater and production wells to improve subsurface performance. Production well performance may be adjusted by controlling backpressure or throttling on the well. Heater well performance may also be adjusted by controlling energy input. Sensor readings may also sometimes imply mechanical problems with a well or downhole equipment which requires repair, replacement, or abandonment.

In one embodiment, flow rate, compositional, temperature and/or pressure data are utilized from two or more wells as inputs to a computer algorithm to control heating rate and/or production rates. Unmeasured conditions at or in the neighborhood of the well are then estimated and used to control the well. For example, in situ fracturing behavior and kerogen maturation are estimated based on thermal, flow, and compositional data from a set of wells. In another example, well integrity is evaluated based on pressure data, well temperature data, and estimated in situ stresses. In a related embodiment the number of sensors is reduced by equipping only a subset of the wells with instruments, and using the results to interpolate, calculate, or estimate conditions at uninstrumented wells. Certain wells may have only a limited set of sensors (e.g., wellhead temperature and pressure only) where others have a much larger set of sensors (e.g., wellhead temperature and pressure, bottomhole temperature and pressure, production composition, flow rate, electrical signature, casing strain, etc.).

As noted above, there are various methods for applying heat to an organic-rich rock formation. For example, one method may include electrical resistance heaters disposed in a wellbore or outside of a wellbore. One such method involves the use of electrical resistive heating elements in a cased or uncased wellbore. Electrical resistance heating involves directly passing electricity through a conductive material such that resistive losses cause it to heat the conductive material. Other heating methods include the use of downhole combustors, in situ combustion, radio-frequency (RF) electrical energy, or microwave energy. Still others include injecting a hot fluid into the oil shale formation to directly heat it. The hot fluid may or may not be circulated.

One method for formation heating involves the use of electrical resistors in which an electrical current is passed through a resistive material which dissipates the electrical energy as heat. This method is distinguished from dielectric heating in which a high-frequency oscillating electric current induces electrical currents in nearby materials and causes them to heat. The electric heater may include an insulated conductor, an elongated member disposed in the opening, and/or a conductor disposed in a conduit. An early patent disclosing the use of electrical resistance heaters to produce oil shale in situ is U.S. Pat. No. 1,666,488. The '488 patent issued to Crawshaw in 1928. Since 1928, various designs for downhole electrical heaters have been proposed. Illustrative designs are presented in U.S. Pat. No. 1,701,884, U.S. Pat. No. 3,376,403, U.S. Pat. No. 4,626,665, U.S. Pat. No. 4,704,514, and U.S. Pat. No. 6,023,554).

A review of application of electrical heating methods for heavy oil reservoirs is given by R. Sierra and S. M. Farouq Ali, “Promising Progress in Field Application of Reservoir Electrical Heating Methods”, Society of Petroleum Engineers Paper 69709, 2001. The entire disclosure of this reference is hereby incorporated by reference.

Certain previous designs for in situ electrical resistance heaters utilized solid, continuous heating elements (e.g., metal wires or strips). However, such elements may lack the necessary robustness for long-term, high temperature applications such as oil shale maturation. As the formation, heats and the oil shale matures, significant expansion of the rock occurs. This leads to high stresses on wells intersecting the formation. These stresses can lead to bending and stretching of the wellbore pipe and internal components. Cementing (e.g., U.S. Pat. No. 4,886,118) or packing (e.g., U.S. Pat. No. 2,732,195) a heating element in place may provide some protection against stresses, but some stresses may still be transmitted to the heating element.

As an alternative, international patent publication WO 2005/010320 teaches the use of electrically conductive fractures to heat the oil shale. A heating element is constructed by forming wellbores and then hydraulically fracturing the oil shale formation around the wellbores. The fractures are filled with an electrically conductive material which forms the heating element. Calcined petroleum coke is an exemplary suitable conductant material. Preferably, the fractures are created in a vertical orientation extending from horizontal wellbores. Electricity may be conducted through the conductive fractures from the heel to the toe of each well. The electrical circuit may be completed by an additional horizontal well that intersects one or more of the vertical fractures near the toe to supply the opposite electrical polarity. The WO 2005/010320 process creates an “in situ toaster” that artificially matures oil shale through the application of electric heat. Thermal conduction heats the oil shale to conversion temperatures in excess of 300° C., causing artificial maturation.

International patent publication WO 2005/045192 teaches an alternative heating means that employs the circulation of a heated fluid within an oil shale formation. In the process of WO 2005/045192, supercritical heated naphtha may be circulated through fractures in the formation. This means that the oil shale is heated by circulating a dense, hot hydrocarbon vapor through sets of closely-spaced hydraulic fractures. In one aspect, the fractures are horizontally formed and conventionally propped. Fracture temperatures of 320°-400° C. are maintained for up to five to ten years. Vaporized naphtha may be the preferred heating medium due to its high volumetric heat capacity, ready availability and relatively low degradation rate at the heating temperature. In the WO 2005/045192 process, as the kerogen matures, fluid pressure will drive the generated oil to the heated fractures where it will be produced with the cycling hydrocarbon vapor.

The purpose for heating the organic-rich rock formation is to pyrolyze at least a portion of the solid formation hydrocarbons to create hydrocarbon fluids. The solid formation hydrocarbons may be pyrolyzed in situ by raising the organic-rich rock formation, (or zones within the formation), to a pyrolyzation temperature. In certain embodiments, the temperature of the formation may be slowly raised through the pyrolysis temperature range. For example, an in situ conversion process may include heating at least a portion of the organic-rich rock formation to raise the average temperature of the zone above about 270° C. at a rate less than a selected amount (e.g., about 10° C., 5° C.; 3° C., 1° C., 0.5° C., or 0.1° C.) per day. In a further embodiment, the portion may be heated such that an average temperature of the selected zone may be less than about 375° C. or, in some embodiments, less than about 400° C. The formation may be heated such that a temperature within the formation reaches (at least) an initial pyrolyzation temperature (e.g., a temperature at the lower end of the temperature range where pyrolyzation begins to occur).

The pyrolysis temperature range may vary depending on the types of formation hydrocarbons within the formation, the heating methodology, and the distribution of heating sources. For example, a pyrolysis temperature range may include temperatures between about 270° C. and about 900° C. Alternatively, the bulk of the target zone of the formation may be heated to between 300° to 600° C. In an alternative embodiment, a pyrolysis temperature range may include temperatures between about 270° C. to about 500° C.

Preferably, for in situ processes the heating of a production zone takes place over a period of months, or even four or more years. Alternatively, the formation may be heated for one to fifteen years or, alternatively, 3 to 10 years, 1.5 to 7 years, or 2 to 5 years. The bulk of the target zone of the formation may be heated to between 270° to 800° C. Preferably, the bulk of the target zone of the formation is heated to between 300° to 600° C. Alternatively, the bulk of the target zone is ultimately heated to a temperature below 400° C. (752° F.).

In certain embodiments of the methods of the present invention, downhole burners may be used to heat a targeted organic-rich rock formation. Downhole burners of various designs have been discussed in the patent literature for use in oil shale and other largely solid hydrocarbon deposits. Examples include, in numerical order, U.S. Pat. No. 2,887,160; U.S. Pat. No. 2,847,071; U.S. Pat. No. 2,895,555; U.S. Pat. No. 3,109,482; U.S. Pat. No. 3,225,829; U.S. Pat. No. 3,241,615; U.S. Pat. No. 3,254,721; U.S. Pat. No. 3,127,936; U.S. Pat. No. 3,095,031; U.S. Pat. No. 5,255,742; and U.S. Pat. No. 5,899,269.

Downhole burners operate through the transport of a combustible fuel (typically natural gas) and an oxidant (typically oxygen-enriched air) to a subsurface position in a wellbore. The fuel and oxidant react downhole to generate heat. The combustion gases are removed (typically by transport to the surface, but possibly via injection into the formation). Downhole burners may utilize pipe-in-pipe arrangements to separately transport fuel and an oxidant downhole, and then to remove the flue gas back up to the surface. Some downhole burners generate a flame, while others may not.

The use of downhole burners is an alternative to other downhole heating methods such as electrical resistance heating and radio-frequency heating. In principle, downhole heating methods can be more efficient than these electrical methods since the energy losses (typically about 50%) associated with generating electricity from combustible fuels are avoided. Downhole burners also reduce infrastructure cost. In this respect, there is no need for an expensive electrical power plant and distribution system. The use of downhole burners is also an alternative to another form of downhole heat generation called steam generation. In downhole steam generation, a combustor in the well is used to boil water placed in the wellbore for injection into the formation. Applications of the downhole heat technology have been described in F. M. Smith, “A Down-hole burner—Versatile tool for well heating,” 25^(th) Technical Conference on Petroleum Production, Pennsylvania State University, pp 275-285 (Oct. 19-21, 1966); H. Brandt, W. G. Poynter, and J. D. Hummell, “Stimulating Heavy Oil Reservoirs with Downhole Air-Gas Burners,” World Oil, pp. 91-95 (September 1965); and C. I. DePriester and A. J. Pantaleo, “Well Stimulation by Downhole Gas-Air Burner,” Journal of Petroleum Technology, pp. 1297-1302 (December 1963).

Downhole heating can also be more efficient than the circulation of surface-heated fluids. This is especially true for deep targets since heat losses to the overburden can be largely avoided.

Downhole burners also have advantages over electrical heating methods due to the reduced infrastructure cost. In this respect, there is no need for an expensive electrical power plant and distribution system. Moreover, there is increased thermal efficiency because the energy losses inherently experienced during electrical power generation are avoided.

Various challenges are presented by the use of downhole burners for heating a formation. As a result, there have been few major field applications of downhole burners. Key design issues include temperature control and metallurgy limitations. In this respect, the flame temperature in a burner can overheat the tubular and burner hardware, causing them to fail via melting, thermal stresses, loss of tensile strength, or creep. Certain stainless steels, typically with high chromium content, can tolerate temperatures up to about 700° C. for extended periods. (See, for example, H. E. Boyer and T. L. Gall (eds.), Metals Handbook, Chapter 16: “Heat-Resistant Material”, American Society for Metals, (1985.)) Another drawback is that the flames generated by the downhole burner can cause hot spots within the burner and in the formation surrounding the burner. This is due to radiant heat transfer from the luminous portion of the flame. A typical gas flame can produce temperatures up to about 1,650° C. Therefore, materials of construction for the burners must be sufficient to withstand the temperatures of these hot spots. Use of refractory metals or ceramics can help solve these problems, but typically at a higher cost. Ceramic materials with acceptable strength at temperatures in excess of 900° C. are preferred. These would include high alumina content ceramics. Other ceramics that may be useful include chrome oxide, zirconia oxide, and magnesium oxide-based ceramics.

Additionally, the flue gases generated by the downhole burner can be corrosive due to CO₂ and water content. This is particularly if the water condenses. Use of alloy metals such as stainless steels can be used to reduce this potential problem.

Heat transfer in a pipe-in-pipe arrangement for a downhole burner can also lead to difficulties. The down-going fuel and air will heat exchange with the up-going hot flue gases. In a well there is minimal room for a high degree of insulation and, hence, significant heat transfer is possible. This cross heat-exchange can cause significant heating of the air and fuel prior to entering the burner. This, in turn, can lead to significantly higher-than-expected flame temperatures. Cross heat-exchange can also heat the flue gas moving up past the burner. If the burner is near the top of the target formation, the flue gas thus transports otherwise useful heat into the overburden where it is neither needed nor desired. Additionally, the cross heat exchange can limit the transport of heat downstream of the burner since the hot flue gases may rapidly lose heat energy to the rising cooler flue gases.

For downhole burner applications, heat transfer can occur in one of several ways. These include conduction, convection, and radiative methods. Radiative heat transfer can be particularly strong for an open flame. Therefore, it is desirable to provide a heater well having a downhole burner that harnesses the heat of the burner and more uniformly distributes it across a zone of interest. One approach to address this issue is to use two or more smaller burners spaced apart over a desired depth range to provide more uniform heating. In one aspect, a desired length of 50 meters, 100 meters, or 200 meters is heated. Another approach is to reduce temperatures near the burner so as to avoid excess use of costly refractory materials. Also addressed herein is maximizing efficiency of heating the target formation by reducing the temperature of the flue gas initially entering the target formation.

A method for in situ heating of a selected portion of a targeted organic-rich rock formation is provided herein. Preferably, the organic-rich rock formation comprises oil shale. In one embodiment, the method includes providing casing in a wellbore extending to a depth of the organic-rich rock formation, and also providing a tubing within the casing. An annular area is defined between the tubing and the casing. Preferably, the casing is isolated to flow from the surrounding formation.

The method also includes the step of injecting air (or other oxidant) and a combustible fuel into the wellbore. Either the air or the combustible fuel is in stoichiometric combustion excess over the other. Hardware is provided in the wellbore so as to cause the air and the combustible fuel to mix and to combust into flue gas at substantially the depth of the targeted portion of the organic-rich rock formation. The hardware includes one or more burners.

The method further includes moving flue gas up the annular region between the tubing and the surrounding casing. Insulation is provided along the tubing proximate each of the one or more burners. Preferably the insulation is placed below the depth of the shallowest burner. The insulation layer may comprise ceramic. Together with excess gas flow, the insulation serves to reduce the heat transfer coefficient within the tubing and to provide a more uniform temperature within the casing along the selected portion of the organic-rich rock formation. The uniformity of the temperature profile along the well can be optimized via the choice of the insulation amount and the amounts of excess air or fuel.

In one aspect, the temperature along the selected portion of the organic-rich rock formation is between about 300° C. and 900° C. More preferably, the temperature along the selected portion of the organic-rich rock formation is between 300° C. and 700° C. The temperature of the flue gas may be monitored at a point in the casing, such as near the depth of the first burner.

The first burner may be positioned at any depth within the organic-rich rock formation. For example, the first burner may be placed near the top of the organic-rich rock formation. Alternatively, the first burner may be placed within 50 meters of the top of the organic-rich rock formation. Alternatively still, the first burner may be placed within 20 meters of the top of the organic-rich rock formation. Preferably, each of the one or more burners is centralized within the tubing.

In one embodiment of the methods, the hardware comprises a first tubular member residing within the tubing extending to the selected portion of the organic-rich rock formation, and a first burner at a first depth within the organic-rich rock formation. The first burner is preferably at the lower end of the first tubular member. Preferably, the first tubular member separates the air and combustible fuel prior to reaching the first burner. Optionally, the hardware also includes a first tubular cowl disposed immediately below the first burner.

In this embodiment, the hardware also comprises a second tubular member residing within the tubing. The second tubular member has a lower end extending to the selected portion of the organic-rich rock formation at a second depth that is lower than the first depth. The second burner is positioned proximate the lower end of the second tubular member. The hardware may further comprise a second tubular cowl disposed at the lower end of the second tubular member immediately below the second burner. In one aspect, the first burner and the second burner are each separated by about 20 to 150 meters. Alternatively, the first burner and the second burner are each separated by about 40 to 100 meters.

The hardware may further comprise a third tubular member residing within the tubing. The third tubular member has a lower end extending to the organic-rich rock formation at a third depth lower than the second depth. The third tubular member also has a third burner at its lower end. A third tubular cowl may be disposed at the lower end of the third tubular member and immediately below the third burner. In one aspect, the first burner, the second burner, and the third burner are each separated by about 20 to 60 meters.

It is preferred that insulation be placed along the tubing. In one aspect an insulation layer is placed along the tubing proximate each of the first, second and third burners. In another aspect the insulation layer runs the length of the tubing at the depth of the organic-rich rock formation.

In another embodiment, a first burner is positioned along a tubular member at a first depth within the selected portion of the organic-rich rock formation, and a second burner is positioned along the first tubular member at a second depth within the selected portion of the organic-rich rock formation. The second depth is below the first depth. The first and second burners may be disposed in an annular region defined between the tubular member and the surrounding tubing.

A first tubular cowl may be disposed at the first depth immediately below the first burner. Likewise, a second tubular cowl may be disposed at the second depth immediately below the second burner. In one aspect, the first burner and the second burner are each separated within the annular region by about 20 to 150 meters.

In this embodiment, a third burner may be positioned along the first tubular member and within the annular region at a third depth within the selected portion of the organic-rich rock formation. A third tubular cowl may optionally be disposed at the third depth immediately below the third burner. An insulation layer is then placed along an inner surface of the tubing proximate each of the first, second and third burners. In one aspect, the first burner, the second burner, and the third burner are each separated by about 20 to 100 meters. Alternatively, the first burner, the second burner, and the third burner are each separated by about 40 to 60 meters.

In any of these embodiments, a portion of the tubing proximate the first depth is preferably constructed from an alloy or metal having a higher maximum working temperature than a remaining portion of the tubing. The portion of the tubing having a higher maximum working temperature may, in one aspect, reside proximate the first depth and below, for example, about 10 meters above the first depth, and extend down to about 20 meters below a lowermost burner within the wellbore. Alternately, individual portions of tubing having higher maximum working temperatures may be located proximate the depth of each respective burner.

For any of the above-described embodiments, it is desirable to maintain a substantially uniform temperature profile along the burners and within the annular area defined between the tubing and the surrounding casing. To this end, various parameters may be adjusted. For example, the positions of the burners, the rate of injecting the combustible fuel, the rate of injecting the air, or combinations thereof, may be specified so that the temperature of the flue gas traveling up the annulus is about 300° C. to 750° C. across the selected portion of the organic-rich rock formation. Also, the rate of injecting the combustible fuel may be reduced over time so as to maintain a desired temperature range as the surrounding formation warms.

During operation, the flue gas circulated up through the annulus within the casing may be collected at the surface. The flue gas may be compressed, and then mixed with compressed air containing oxygen. This mixture of compressed flue gas and compressed air may be injected back into the wellbore. Alternatively, the compressed flue gas may be mixed with combustible gases and then delivered back into the wellbore as combustible fuel.

In one aspect, returned flue gas is collected at the surface and then monitored for the presence of combustible species. The purpose is to assess whether any of the burners are not firing properly. Combustible species may include, for example, methane, ethane, hydrogen (H₂), and carbon monoxide.

In another embodiment, the returned flue gas may be vented to the atmosphere. In this instance it is desirable to treat the flue gas to remove NO_(x) components prior to venting the received flue gas.

The one or more burners may be ignited in various ways. For example, the burners may be ignited using electric resistive heating elements. In one aspect, the first burner and the second burner are ignited using a removable electrical heating element which can be selectively inserted into the first and second tubular members. Alternatively, the burners may be ignited by injecting a pyrophoric substance into the tubular members. The pyrophoric substance may be, for example, liquid triethylborane.

For purposes of causing combustion, the hardware may include at least one fuel line for delivering the injected fuel to the burners. The at least one fuel line may be, for example, a single fuel line disposed within the annulus outside of the tubing. Alternatively, the at least one fuel line may be a fuel line residing in each of the tubular members.

The air may be injected into the wellbore in various ways. Excess air may be injected to reduce, control, and optimize the combustion gas temperature. In one aspect, the air is injected in excess at a mass rate of 1.25 to 6.0 times the stoichiometric combustion amount. Alternatively, the air may be injected relative to the combustible fuel at 2.0 to 5.0 times stoichiometric. In one embodiment, the air is injected at a rate of about 10,000 to 50,000 kg/day. Alternatively, the air is injected at a rate of about 10,000 to 25,000 kg/day. In one embodiment, the air is injected under a pressure of about 50 to 250 psia. In one embodiment, the burners are sized to deliver 200 to 3,000 watts per meter of formation length desired to be heated.

The combustible fuel may also be injected into the wellbore in various ways. In one aspect, the combustible fuel is injected under a pressure of greater than about 200 psia. Alternatively, the combustible fuel is injected under a pressure of greater than about 600 psia. Alternatively still, the combustible fuel may be injected under a pressure of only about 100 to 200 psia.

The method may further comprise the step of heating the oil shale in order to pyrolyze at least a portion of the oil shale into hydrocarbon fluids. The hydrocarbon fluids will include gas. In this instance, the method will also include producing the gas. The combustible fuel may at least partially comprise gas produced from the hydrocarbon fluids. In this instance, the method may further include treating the hydrocarbon fluids and/or the gas in order to substantially remove H₂S from the gas before re-injecting the gas into the tubular members.

It is preferred that the heat transfer coefficient between the down-flowing flue gas within the tubing and the up-flowing flue gas in the annulus around the tubing be low. In one aspect, the heat transfer coefficient between the combusted fuel within the tubing and the flue gas in the annulus proximate the burner is less than about 50 W/m² C and, more preferably is about 25 W/m² C. The insulation helps to reduce the heat transfer coefficient. In one aspect, additional insulation is placed inside the tubing within 10 meters before a burner and extending at least 10 meters below that burner to reduce the temperature experienced by the metal tubing.

Also disclosed herein is a heater well for in situ heating of a targeted organic-rich rock formation. In one embodiment, the heater well includes a casing in a wellbore extending to a depth of the organic-rich rock formation. Preferably, the casing is substantially sealed to the formation so that fuel and flue gases are substantially isolated from in situ formation fluids. Part of substantially sealing the casing to the formation may include the use of cementing the casing within the formation. For example, the casing may be placed in the wellbore with an open bottom. The open bottom may then be sealed to the formation through the placement of cement in the bottom of the wellbore. Alternatively, the bottom of the casing may be capped, for example by welding a metal plate onto the bottom end at the surface, in order to substantially seal the casing from the formation.

A tubing is disposed within the casing. An annulus is thereby formed between the tubing and the surrounding casing. A first tubular member resides within the tubing. The first tubular member extends to a first depth within the organic-rich rock formation. A first burner is placed proximate a bottom end of the first tubular member.

The heater well also has a second tubular member residing within the tubing. The second tubular member extends to a second depth that is lower than the first depth within the organic-rich rock formation. A second burner is placed proximate a bottom end of the second tubular member.

A first insulation layer is disposed on the tubing proximate the first burner and below. The first insulation layer may be along an outer diameter of the tubing. The first insulation layer serves to reduce the heat transfer coefficient within the tubing. When properly combined with excess air or fuel flow, this can lead to a more uniform temperature profile in the wellbore. Additional insulation may be disposed proximate each of the first and second burners along an inner diameter of the tubing to protect the metal from extreme temperatures caused by the burner flames.

In one aspect, a first tubular cowl is disposed immediately below the first burner. In addition, a second tubular cowl is disposed immediately below the second burner. The cowls serve to further reduce the heat transfer coefficient within the tubing by limiting the amount of heat distributed immediately below the respective burners.

In one aspect, the heater well also has a third tubular member residing within the tubing. The third tubular member extends to a third depth that is lower than the second depth within the organic-rich rock formation. A third burner is placed proximate a bottom end of the third tubular member. An insulation layer may then reside along the tubing proximate the third burner.

Another heater well for in situ heating of an organic-rich rock formation is also disclosed herein. In this embodiment, the heater well comprises a casing in a wellbore. The wellbore extends to a depth of the organic-rich rock formation. Preferably, the casing is substantially sealed to the formation. A tubing is disposed within the casing. An annulus is thereby formed between the tubing and the surrounding casing. A tubular member resides within the tubing and also extends to a first depth within the organic-rich rock formation. An annular region is thereby also formed between the tubular member and the surrounding tubing.

A first burner is positioned along the tubular member at a first depth within the selected portion of the organic-rich rock formation. A second burner is also positioned along the first tubular member at a second depth within the selected portion of the organic-rich rock formation. The second depth is below the first depth. The first and second burners are preferably placed within the annular region between the tubular member and the surrounding tubing.

A first insulation layer is disposed on an outer diameter of the tubing proximate the first burner and below. The first insulation layer serves to reduce the heat transfer coefficient within the tubing, which when properly combined with excess air or fuel flow can lead to a more uniform temperature profile in the wellbore. Additional insulation may be disposed proximate each of the first and second burners on an inner diameter of the tubing to protect the metal from extreme temperatures caused by the burner flames.

In one aspect, a first tubular cowl is disposed immediately below the first burner. In addition, a second tubular cowl is disposed immediately below the second burner.

In one aspect, the heater well also has a third burner positioned along the tubular member at a third depth within the selected portion of the organic-rich rock formation. The third depth is lower than the second depth. An insulation layer resides along the tubing proximate the third burner.

FIG. 29 provides a cross-sectional view of a heater well 2900, in one embodiment. The heater well 2900 resides within a wellbore 2904 that extends from an earth surface 2902 to a targeted organic-rich rock formation 2905. The organic-rich rock formation 2905 may include tar sands, coal, oil shale, or other rock containing solid hydrocarbons. Preferably, the organic-rich rock formation 2905 is an oil shale containing kerogen that may be pyrolyzed.

The purpose of the heater well 2900 is to generate heat into the surrounding organic-rich rock formation 2905. More specifically, the heater well 2900 heats the formation 2905 to a temperature that is sufficient to pyrolyze solid hydrocarbons such as kerogen into hydrocarbon fluids. In the present invention, this is done through the use of combustive heat.

Air “A” and a combustible fuel “CF” are injected into the wellbore 2900. The air “A” and combustible fuel “CF” are mixed at a downhole burner 2938, where the fuel combusts and forms a flame. Excess air “A”, if present, and flue gas “FG” flow beyond the burner 2938, down the wellbore 2904, and back up to the surface 2902.

The wellbore 2904 is cased. A string of casing 2910 is shown extending to a lower end 2912 of the wellbore 2904. The lower end 2912 of the wellbore 2904 is closed in order to create a closed heater well system. Closure may be provided by means of a plate 2913, as shown in FIG. 29. Alternatively, closure may be provided through cement injected into the wellbore 2904 during completion. The casing 2910 defines a bore 2915 which, as will be discussed further below, receives the burner 2938 and other hardware for heating the surrounding organic-rich rock formation 2905.

The heater well 2900 also includes a string of tubing 2920. The tubing 2920 serves as an inner tubing relative to the casing 2910. Thus, a pipe-in-pipe heater arrangement is formed. The tubing 2920 has a lower end 2922 that extends substantially to the lower end 2912 of the wellbore 2904. The lower end 2912 is open. The tubing 2920 and surrounding casing 2910 define an annulus 2914 therebetween.

The burner 2938 in the heater well 2900 preferably comprises a plurality of burners. In the illustrative arrangement of FIG. 29, each burner 2938 is disposed at the bottom of a tubular member 2930. Three tubular members 2930 a, 2930 b, 2930 c are shown in wellbore 2905, and corresponding burners are indicated as 2938 a, 2938 b and 2938 c. However, it is understood that any number of tubular members 2930 and corresponding burners 2938 may be used. Indeed, only one tubular member 2930 and one corresponding burner 2938 may be chosen.

The tubular members 2938 a, 2938 b, 2938 c are preferably fabricated from stainless steel. An annulus 2924 is formed between the tubular members 2930 a, 2930 b and 2930 c and the surrounding tubing 2920.

FIG. 30 provides a top view of the heater well 2900 of FIG. 29. Here, the tubing 2920 and the surrounding outer casing 2910 are seen. In addition, the three tubular members 2930 a, 2930 b, 2930 c are also seen. Centralizers (not shown) may optionally be used to maintain an equidistant spacing of the tubular members 2930 a, 2930 b, 2930 c within a bore 2925 of the tubing 2920.

FIG. 31 shows a side view of one of the burners 2938 disposed at the bottom 2932 of a tubular member 2930. Tubular member 2930 is representative of any of tubular members 2930 a, 2930 b or 2930 c from the heater well 2900 of FIG. 29. It can be seen from both FIG. 29 and FIG. 31 that a cowl 2940 is disposed immediately below the burner 2938. The cowl 2940 is preferably fabricated from a heat-resistant material. For example, the cowl 2940 may be fabricated from ceramic or a refractory metal or other temperature resistant steel.

The cowl 2940 is a tubular body having a wall 2942 and a bore 2945 therein. The wall 2942 has a plurality of perforations or vents 2946 that provide fluid communication between the inner bore 2945 and the surrounding annulus 2924. In the illustrative cowl 2940 of FIG. 31, flanges 2944 extend outwardly from the wall 2942 to create the vents 2946. The vents 2946 receive air, indicated at arrow “A,” from the annulus 2924. The air “A,” in turn, mixes with combustible fuel, shown at arrow “CF,” to enable the burner 2938 to create a flame. In addition to aiding mixing, the cowl may serve to prevent excessive radiative heat transfer from the flame to the surrounding tubing 2920. Although not depicted in FIG. 31, the arrangement of the air “A” and combustible fuel “CF” may be reversed such that the vents 2946 receive combustible fuel “CF” from the surrounding annulus 2924 which mixes with air “A” from the inner bore 2945 to enable the burner 2938 to create a flame.

Various ways may be provided for igniting the combustible fuel “CF.” For instance, the fuel “CF” may be ignited using electric resistive heating elements in the tubular members 2930. In one aspect, the resistive heating elements are removable electrical heating elements which can be selectively inserted into the tubular members 2930. In another aspect, the fuel “CF” and burners 2938 may be ignited by injecting a pyrophoric substance into the tubular members 2930. The pyrophoric substance may be either a liquid or a solid substance.

Igniting a burner 2938 creates a flame. Those of ordinary skill in the art will appreciate that the flame generated from a downhole burner, such as burners 2938 a, 2938 b and 2938 c generates a flame that is extremely hot. In one aspect, the flame and the circulation of flue gas “FG” through the heater well 2900 causes the targeted organic-rich rock formation 2905 to be heated to between about 300° C. and 700° C. The use of such a downhole burner 2938 creates a point of very high heat which diminishes as the flue gas “FG” is circulated through the heater well 2900. The use of cowls 2940 helps to contain radiant heat and to cool the hot flue gases “FG” with air “A.” In this way, only the cowl 2940 and perhaps a relatively short length of the surrounding tubing 2920 needs to be constructed from special temperature-resistant materials. The cowls 2940 employ an elongated body 2942 which insulates the surrounding tubing 2920 from immediate contact with the flames. The elongated body 2942 also provides for a more uniform heat distribution from the flames to the surrounding tubing 2920 and, ultimately, the organic-rich rock formation 2905.

Additional approaches may be taken to provide for a more uniform heat distribution from the flames to the surrounding tubing 2920 and, ultimately, the organic-rich rock formation 2905. In one aspect, the volume of air “A” injected into the wellbore 2925 may be increased. For example, the air “A” may be injected at about 1.25 to 6.0 or, more preferably, 2.0 to 5.0 times the stoichiometric combustion amount. Alternatively, or in addition, an insulative layer may be placed along the tubing 2920 at and below the level of the uppermost burner 2938 a, that is, the burner disposed at the bottom of tubular member 2930 a.

Returning to FIG. 29, it can be seen that various items of surface equipment are shown. First, a compressor 2954 is seen. The compressor 2954 receives air “A” from an intake line 2952. The compressor 2954 pressurizes the air “A” and then delivers it to the tubing 2920 via line 2956. Once again, arrow “A” demonstrates the injection of air into the tubing 2920. More specifically, in the illustrative wellbore 2925 air “A” is injected into the annulus 2924 of the tubing 2920.

The surface equipment also includes a fuel tank 2964. The fuel tank 2964 stores combustible fuel “CF” that is injected into the tubular members 2930 a, 2930 b, and 2930 c. Fuel may be fed into the fuel tank 2964 through an input line 2966. Fuel may be gaseous or liquid. Alternatively, the tank 2964 may be periodically refilled from a delivery truck or other source. The combustible fuel “CF” is injected into the tubular members 2930 a, 2930 b, and 2930 c via an injection line 2962. The injection line 2962 may be manifolded as shown in FIG. 29 to allow a single line to feed fuel “CF” into all of the tubular members 2930 a, 2930 b, and 2930 c. It is understood that a fuel line (not shown) may also be used to deliver fuel “CF” immediately to the respective burners 2938 a, 2938 b, 2938 c downhole. Such fuel lines may reside in each of the first 2930 a, second 2930 b and third 2930 c tubulars.

In order to create the heat-generating flames from the burners 2938 a, 2938 b, 2938 c, combustible fuel “CF” is injected into the respective tubular members 2930 a, 2930 b, and 2930 c under pressure. In one aspect, the combustible fuel “CF” is injected under a pressure of greater than about 200 psia. In another aspect, the combustible fuel “CF” is injected under a pressure of greater than about 600 psia. In still another aspect, the combustible fuel “CF” is injected under a pressure of only about 100 to 200 psia.

It is seen in FIG. 29 that the downhole burners 2938 a, 2938 b, and 2938 c are positioned at varying depths. The purpose is to create a series of staged heat sources at different levels or depths within the targeted formation 2905. Stated another way, flue gas “FG” is generated at different intervals along the wellbore 2900 to create a more uniform thermal convection profile away from the heater well 2900 and into the formation 2905.

FIG. 29 indicates arrows “FG” demonstrating the flow of heated flue gases down from each burner 2938 a, 2938 b, 2938 c. The flue gas “FG” is circulated to the lower end 2912 of the casing 2910 and into the annulus 2914 around the tubing 2920. The flue gas “FG” then moves up the annulus 2914 where it carries hot flue gas “FG” to warm the casing 2910 and the surrounding formation 2905.

A heat transfer coefficient exists between the downward-flowing air “A” within the tubing 2920 and the upward-flowing flue gas “FG” in the annulus 2914. In one aspect, the heat transfer coefficient is greater than about 75 W/m² C above the top burner location. More preferably, the heat transfer coefficient between the air “A” within the tubing 2920 and the flue gas “FG” in the annulus 2914 is greater than about 150 W/m²C above about the top burner location.

A heat transfer coefficient also exists between the downflowing flue gas “FG” within the tubing 2920 and the upflowing flue gas “FG” in the annulus 2914. In one aspect, the heat transfer coefficient is between about 10 and 40 W/m² C below about the top burner 2938 a location. More preferably, the heat transfer coefficient between the downflowing flue gas “FG” within the tubing 2920 and the upflowing flue gas “FG” in the annulus 2914 is between about 10 to 30 W/m²C below the depth of the top burner 2938 a.

The flue gas “FG” is circulated to the surface 2902. Once at the surface 2902, the flue gas “FG” may be vented to the atmosphere. In this instance, the flue gas “FG” is preferably treated to reduce NO_(x) components prior to venting. Alternatively if the flue gas “FG” still has significant oxygen content or significant fuel content, the flue gas “FG” may be redirected to be used as an oxidant or fuel supply for another well or surface combustor. FIG. 29 shows the flue gas “FG” being captured by line 2972, and then being delivered to a separator 2974. The separator 2974 is preferably a scrubber used to remove potential pollutants comprising, NO_(x), SO₂, or particulates from the flue gas “FG.”

In one aspect (not shown), the collected flue gas “FG” is compressed. The flue gas “FG” containing oxygen, preferably >10 mol %, may then be mixed with compressed air. The mixture is then delivered back into the annulus 2924 together as air “A.” Recapturing the flue gas “FG” allows the step of injecting the air “A” to use the pressure from the flue gas “FG,” thereby reducing compression needs at the heater well 2900. In other words, the size or capacity of compressor 2954 is reduced.

In another aspect shown in FIG. 29, the collected flue gas “FG” is compressed. The flue gas “FG” containing combustible gases, preferably >25 mol %, “FG” may then be mixed with compressed fuel. The mixture is then delivered back into the tubular members 2930 a, 2930 b, and 2930 c together as combustible fuel “CF.” The combustible fuel “CF” may comprise, for example, methane, ethane or mixtures of combustible gas species.

In another aspect, the flue gas “FG” is again collected from the heater well 2900 at the surface 2902. The flue gas “FG” may then be monitored for the presence of combustible species to assess whether the burners 2938 are firing properly. The combustible species may comprise at least one of methane, ethane, hydrogen (H₂), and carbon monoxide.

As noted, the tubing 2920 is preferably insulated at depths adjacent and immediately below the respective burners 2938 a, 2938 b, and 2938 c. Such insulation is preferably along the outer diameter of the tubing 2920. For example, insulation may be provided by cladding or bonding a ceramic material to the tubing 2920. Such an insulative layer is shown in FIG. 29 at 2918.

The insulative layer 2918 moderates the heat transfer coefficient between the downflow of flue gas “FG” within the tubing 2920 and the upward flow of flue gas “FG” in the annulus 2914. In this respect, hot flue gas “FG” moving downward within the tubing 2920 can experience heat transfer with flue gas “FG” moving upward in the annulus 2914. This is particularly beneficial at points immediately below the burners 2938 a, 2938 b, and 2938 c. High heat transfer at depths below the burners 2938 a, 2938 b, and 2938 c leads to a short zone of heating around the wellbore 2904 since the downflowing hot gas “FG” within the pipes 2930 a, 2930 b, and 2930 c quickly loses heat to the upgoing cooler flue gas “FG” in the annulus 2924. On the other hand, a very low heat transfer coefficient below the burners 2938 a, 2938 b, and 2938 c leads to little heat loss from the downflowing hot gases “FG,” leading to unnecessarily high temperatures in the upgoing flue gas “FG” used to heat the formation 2905.

To moderately reduce the heat transfer coefficient and to create a more uniform heat profile away from the wellbore 2900 in the organic-rich formation 2905, the insulative layer 2918 is provided. In one aspect, the heat transfer coefficient is reduced by a factor of at least two compared to uninsulated regions within the wellbore 2904 or as compared to the heat transfer coefficient without an insulative layer 2918. More preferably, the heat transfer reduction is reduced by a factor of at least four.

As noted, heat transfer may also occur between the downflowing air “A” in the tubing annulus 2924 and the upflowing flue gas “FG” in the casing annulus 2914. In this respect, the air “A” moving downward within the tubing 2920 can experience heat transfer with the hot flue gases “FG”, moving upward in the annulus 2914. The potential for this heat transfer is particularly high immediately above the burners 2938 a, 2938 b, 2938 c. The insulative layer 2918 again assists in limiting this heat transfer.

To address these issues, and in addition to providing the insulative layer 2918, excess air “A” may be injected into the wellbore 2900. Alternatively, or in addition, excess fuel “CF” may be injected into the wellbore 2900. The use of excess gases and the use of insulating cladding, particularly in combination, can lead to a more uniform temperature profile below the burner 2938.

When excess fuel “CF” is used, it may be desirable to switch the air “A” and fuel “CF” flow paths so that the air “A” will flow through the inner tubular members 2930 a, 2930 b, 2930 c and fuel “CF” through the annulus region 2924. A flame generated by this method is a so-called “reverse diffusion” flame and can lead to lower NOx generation in certain cases.

Using a heater well such as heater well 2900, a method for in situ heating of a targeted organic-rich rock formation is provided herein. In one aspect, the method includes the steps of providing casing 2910 in a wellbore 2904 extending to a depth of the organic-rich rock formation 2905. The casing 2910 preferably has a closed lower end 2912. A tubing 2920 is provided within the casing 2910. The tubing 2920 defines an annulus 2914 between the tubing 2920 and the surrounding casing 2910. The method further includes injecting air and a combustible fuel into the tubing 2920, and providing hardware in the tubing 2920 so as to cause the air and the combustible fuel to mix at substantially the depth of the organic-rich rock formation 2905 and in such a manner that a thermal conduction profile adjacent the wellbore 2904 along a selected portion of the organic-rich rock formation 2905 is substantially uniform. Preferably, the temperature profile in the annular region adjacent the selected portion of the organic-rich rock formation 2905 remains relatively uniform at a temperature between about 300° C. and 900° C. More preferably, the temperature profile along the wellbore 2900 into the formation 2905 remains fairly uniform between about 300° C. and 750° C.

In one embodiment, the hardware comprises a first tubular member 2930 a residing within the tubing 2920 extending to the selected portion of the organic-rich rock formation 2905, and a first burner 2938 a at a first depth within the organic-rich rock formation 2905. The first burner 2938 a is preferably at the lower end of the first tubular member 2930 a. Preferably, the first tubular member 2930 a separates the air and combustible fuel prior to reaching the first burner 2938 a. Optionally, the hardware also includes a first tubular cowl 2940 disposed immediately below the first burner 2938 a

The hardware also comprises a second tubular member 2930 b residing within the tubing 2920. The second tubular member 2930 b has a lower end extending to the selected portion of the organic-rich rock formation 2905 at a second depth that is lower than the first depth. A second burner 2938 b is positioned proximate the lower end of the second tubular member 2930 b. The hardware may further comprise a second tubular cowl 2940 disposed at the lower end of the second tubular member 2930 b immediately below the second burner 2938 b. In one aspect, the first burner 2938 a and the second burner 2938 b are each separated by about 20 to 150 meters. Alternatively, the first burner 2938 a and the second burner 2938 b are each separated by about 40 to 100 meters.

The hardware also preferably comprises an insulation layer 2918 placed along an inner surface of the tubing 2920 proximate at least the first 2938 a and second 2938 b burners. In another aspect, the insulation layer 2918 runs the length of the tubing 2920 at the depth of the organic-rich rock formation 2905.

The hardware may further comprise a third tubular member 2930 c residing within the tubing 2920. The third tubular member 2930 c has a lower end extending to the organic-rich rock formation 2905 at a third depth lower than the second depth. The third tubular member 2930 c also has a third burner 2938 c at its lower end. A third tubular cowl 2940 is disposed at the lower end of the third tubular member 2930 c and immediately below the third burner 2938 c.

In one aspect, the first burner 2938 a, the second burner 2938 b, and the third burner 2938 c are each separated by about 20 to 200 meters. Alternatively, the first burner, the second burner, and the third burner are each separated by about 40 to 150 meters, or by 60 to 120 meters.

Yet another embodiment for a heater well employing downhole burners is provided herein. FIG. 32 presents a cross-sectional view of a heater well 3200 in yet an additional alternate embodiment. The heater well 3200 is disposed in a wellbore 2904 that is completed through an organic-rich rock formation 2905. Preferably, the organic-rich rock formation 2905 comprises oil shale, kerogen, or other solid hydrocarbons that may be pyrolyzed. A plurality of burners 3238 a, 3238 b, and 3238 c is again disposed in the heater well 3200 in order to generate heat needed for pyrolysis.

It is noticed in connection with FIG. 32 that like numbers from FIG. 29 are used to describe like features in FIG. 32. Thus, for example, the wellbore 2904 is cased with a string of casing 2910 that extends down to a lower end 2912 of the wellbore 2904. The lower end 2912 of the wellbore 2904 is again closed in order to create a closed heater well system. Closure may be provided by means of a plate 2913, as shown in FIG. 32. Alternatively, closure may be provided through cement injected into the wellbore 2904 during completion. The casing 2910 once again defines a bore 2915 which receives hardware for heating the surrounding organic-rich rock formation 2905.

The heater well 3200 also includes a string of tubing 2920. The tubing 2920 serves as an inner tubing relative to the casing 2910. Thus, a pipe-in-pipe heater arrangement is once again formed. The tubing 2920 has a lower end 2922 that extends substantially to the lower end 2912 of the wellbore 2904. The lower end 2912 is open. The tubing 2920 and surrounding casing 2910 define an annulus 2914 there between.

The heater well 3200 also comprises a plurality of burners 3238 a, 3238 b, 3238 c. In the illustrative arrangement of FIG. 32, three burners 3238 a, 3238 b, 3238 c are disposed along a first or central tubular member 3230. However, it is understood that any number of burners may be used in the heater well 3200.

The central tubular member 3230 is disposed within the tubing 2920. One or more centralizers 3237 may be used to secure the central tubular member 3230 within the tubing 2920. The centralizers 3237 also secure the position of the burners 3238 a, 3238 b, and 3238 c within the wellbore 2904. An annulus 2924 is formed between the central tubular member 3230 and the surrounding tubing 2920. In the illustrative heater well 3200, the burners 3238 a, 3238 b, and 3238 c reside within the annulus 2924.

FIG. 33 provides a side view of one of the burners 3238 from the heater well 3200 of FIG. 32. A cowl 3240 is seen disposed immediately below the burner 3238. As with cowl 2940 of FIG. 31, cowl 3240 is a tubular body having a wall 3242 and a bore 3245 therein. The wall 3242 has a plurality of perforations or vents 3246 that provide fluid communication between the inner bore 3245 and the surrounding annulus 2924. In the illustrative cowl 3240 of FIG. 33, flanges 3244 extend outwardly from the wall 3242 to create the vents 3246. The vents 3246 receive air, indicated at arrows “A,” from the annulus 2924. The air “A,” in turn, mixes with combustible fuel, shown at arrow “CF,” to enable the burner 3238 to create a flame.

Various ways may be provided for igniting the combustible fuel “CF.” For instance, the fuel “CF” may be ignited using electric resistive heating elements in the tubular member 3230. In one aspect, the resistive heating elements are removable electrical heating elements which can be selectively inserted into the tubular member 3230. In another aspect, the fuel “CF” and burners 3238 may be ignited by injecting a pyrophoric substance into the central tubular member 3230. An example of a suitable pyrophoric substance is triethylborane.

In the burner arrangement of FIG. 33, the burners 3238 a, 3238 b, 3238 c extend outward from the central tubular member 3230. Each of the burners 3238 a, 3238 b, 3238 c includes a flow branch 3243 which provides fluid communication between the various burners 3238 a, 3238 b, 3238 c and a central bore 3235 in the tubular member 3230. A distal end 3247 of the flow branch 3243 connects to the central tubular member 3230.

A plate 3241 is provided at the top of the cowl 3240. The flow branch 3243 is received through the plate 3241. The burner 3238 is disposed below the plate 3241 and within the cowl 3240. As noted above in connection with FIG. 31, the cowl 3240 provides several functions which help provide a more uniform heat distribution across the targeted area within the formation 2905. The elongated body 3242 of the cowl 3240 insulates the surrounding tubing 2920 from immediate contact with the flame. In one aspect, the cowls 3240 are fabricated from ceramic or a refractory metal. Still further, the vents 3246 in the cowl 3240 receive air “A” along its length so as to cool the region immediately around the cowl 3240 to prevent a hot spot.

Additional approaches may be taken to provide for a more uniform heat distribution from the flames to the surrounding tubing 2920 and, ultimately, the organic-rich rock formation 2905. In one aspect, the volume of air “A” injected into the annulus 2924 may again be increased. For example, the air “A” may be injected at about two to five stoichometric. Alternatively, or in addition, an insulative layer may be placed along the tubing 2920 at and below the level of the uppermost burner 3238 a.

Returning to FIG. 32, it can be seen that the various downhole burners 3238 a, 3238 b, and 3238 c are positioned at varying depths. The purpose is to create a series of staged heat sources at different levels or depths within the targeted formation 2905. This further serves to create a more uniform thermal conduction profile away from the wellbore 2904 and into the formation 2905. FIG. 32 indicates arrows “FG” demonstrating the flow of heated flue gas down from each burner 3238.

It is also seen in FIG. 32 that various items of surface equipment are shown. The surface equipment is essentially the same as that described in connection with the heater well 2900 of FIG. 29. This equipment includes, for example the air compressor 2954 for compressing air “A,” and the fuel tank 2964 for storing combustible fuel “CF.”

In operation, air “A” is circulated through the bore 2925 of the tubing 2920. In one aspect, the air “A” is injected in excess at a mass rate of 1.25 to 2.5 times the stoichometric air requirement. In one aspect, the total injected gas rate, i.e., air “A” and fuel “CF,” is about 10,000 to 75,000 kg/day. More preferably, the injected gas rate is about 30,000 to 60,000 kg/day. In one aspect, the air “A” is injected under a pressure of about 50 to 250 psia. These injection values may be applied in connection with the heater well 2900 in FIG. 29 as well.

Circulating the air “A” under pressure carries heated flue gas “FG” towards the lower end 2912 of the casing 2910. The flue gas “FG” is circulated into the annulus 2914 around the tubing 2920. The flue gas “FG” then moves up the annulus 2914 where it carries hot flue gas “FG” to warm the casing 2910 and surrounding formation 2905.

Experiments to obtain a more uniform heat distribution in a downhole combustion heater well are demonstrated in FIGS. 34A, 34B, 34C and 34D. These Figures represent heat transfer simulations in different wellbore arrangements. In each wellbore, an inner tubing and an outer tubing are assumed for a pipe-in-pipe arrangement. The inner tubing may be tubing 2920 as shown in FIG. 29 or FIG. 32, while the outer tubing may be, for example, casing 2910.

Before discussing the charts of FIGS. 34A, 34B, 34C and 34D, it is beneficial to review FIG. 35. FIG. 35 provides a cross-sectional side view of a downhole burner arrangement 3500 assumed in the simulations of FIG. 34A and in accordance with certain aspects of the present inventions. The downhole burner 3500 is disposed within a string of casing 3510. The casing 3510 is preferably capped at a lower end 3514. A cap 3516 is shown in FIG. 35.

The downhole burner 3500 also has an inner tubing 3520. The tubing 3520 is disposed centrally within the casing 3510. Centralizers 3512 are optionally used to hold the tubing 3520 within the casing 3510. Insulation 3518 is placed along the tubing 3520. In one aspect, the insulation 3518 provides a heat transfer coefficient of 22 W/m²° C.

In the wellbore 3500, a downhole burner 3538 is provided. A single burner 3538 is illustrated. The insulation 3518 is placed along an outer diameter of the tubing 3520 adjacent and below the burner 3538. The burner 3538 is a 329 kW burner.

The burner 3538 is run into and resides within the tubing 3520 at the end of a pipe 3530. The pipe 3530 is an elongated tubular member and receives combustible fuel “CF.” A cowl 3540 is preferably placed at the end of the pipe 3530 adjacent or below the burner 3538. The pipe 3530 is optionally centralized within the tubing 3520 using centralizers 3522.

An additional layer of insulation 3528 is optionally added along the tubing 3520. This additional insulation 3528 is disposed immediately along or below the burner 3538. Preferably, the additional insulation is along an inner diameter of the tubing 3520. In one aspect, the insulation 3528 begins about 10 meters above the burner 3538, and extends about 20 meters below the burner 3538. Alternatively, the tubing 3520 along this area of the wellbore 3500 is fabricated from ceramic or other highly heat-resistant material.

An annulus 3515 is formed between the tubing 3520 and the surrounding casing 3530. The annulus 3515 receives air “A.” The air “A” and the combustible fuel “CF” mix at the level of the burner 3538 and ignite, forming a flame 3560.

Referring again now to the simulation charts, FIG. 34A is a graph charting depth in a wellbore (such as wellbore 2900) versus temperature. The depth in the wellbore is charted relative to the location of the burner downhole. In this simulation, a single 329 kW burner was assumed. The burner is located at the zero position on the x-axis.

The wellbore is assumed to be insulated adjacent the burner 3538 such as by using insulation 3518. The overall heat transfer coefficient between the downward air “A” flow and the upward flue gas “FG” flow was U=180 W/m² C above the burner 3538. This is the assumed area without insulation. Below the burner 3538, the heat transfer coefficient was only U=22 W/m² C. This indicates a much lower heat transfer in the region around the assumed insulation layer.

To aid in the movement of heat from inside of the tubing 3520 to outside of the tubing 3520, a high flow rate of air “A” was assumed in the calculations. A total gas rate of 50,000 kg/day was modeled, representing 5.4 times the stoichiometric amount of air need to combust methane fuel.

Those of ordinary skill in the art will appreciate that the stoichiometric amount of oxygen needed to burn methane (assumed as the combustible fuel “CF”) is: CH₄+2O₂→CO₂+2H₂O.

Air is only 21 mol % oxygen. Thus, 9.5 moles of air are needed per mole of CH₄, which is equal to 17.3 kg of air per 1 kg CH₄. (Note that air is 29 grams/mol while CH₄ is 16 grams/mol). Thus, for example, 50,000 kg/day of air at 4 times the stoichiometric implies about 723 kg/day of injected methane fuel.

In FIG. 34A, the average temperatures inside of the tubing 3520 and outside of the tubing 3520 in the annulus 3515 are compared. More specifically, temperatures were compared between the downward air flow “A” and the upward flow of flue gas “FG.” It is noted that it is the temperature in the annular region 3515 (i.e., the outer temperature) that distributes or controls the temperature in the adjacent formation.

As illustrated, the temperature inside of the tubing 3520 reached approximately 825° C. at the depth of the burner 3538, but tapered to approximately 450° C. at 150 meters below the burner 3538. However, the temperature outside of the tubing 3520 reached only about 450° C. at the depth of the burner 3538, but then remained relatively stable within the wellbore below the burner 3538. The temperature outside the tubing 3520 only dropped approximately 75° C. before returning to approximately the same temperature of about 450° C. at 150 meters below the burner 3538. Thus, the temperature of the casing 3510 immediately adjacent the surrounding formation remained substantially uniform, thereby minimizing the “hot spot” effect normally seen in downhole burner applications.

FIG. 34B is another graph charting depth in a wellbore versus temperature. The depth in the wellbore is charted relative to the location of a burner downhole. In this wellbore, a single burner was used, but no insulation was provided along the inner tubing 3520. Because no insulation is used, the heat transfer coefficient is constant above and below the burner 3538. The heat transfer through the inner tubing 3520 is assumed to have a heat transfer coefficient of about 180 W/m²° C. along the relevant length.

To aid in the movement of heat from inside of the inner tubing 3520 to outside of the inner tubing 3520, the flow rate of air “A” was increased to above stoichiometric. This case again modeled 50,000 kg/day total gas representing 5.4 times the stoichiometric amount of air needed to combust methane fuel.

As illustrated, the temperature of the inner tubing 3520 rose above 1,000° C. at the depth of the burner, and then dropped to approximately 100° C. at a depth 150 meters below the burner. Similarly, the outer tubing 3510 reached 900° C. near the burner, and then dropped non-linearly to approximately 100° C. at 150 meters below the burner. The extreme temperature profile confirms the utility of insulation around the inner tubing 3520.

FIG. 34C is another graph charting depth in a wellbore versus temperature. The depth in the wellbore is again charted relative to the location of a burner downhole. In this wellbore, a single 320 kW burner is assumed. Insulation 3518 is once again placed along the inner tubing 3520 below the burner 3538 as in the simulation of FIG. 34A. The overall heat transfer coefficient between the downward air “A” flow and the upward flue gas “FG” flow was U=180 W/m² C above the burner 3538. Below the burner 3538, the heat transfer coefficient was U=22 W/m² C. This indicates a much lower heat transfer in the region around the assumed insulation layer.

To aid in the movement of heat from inside of the inner tubing 3520 to outside of the inner tubing 3520, the flow rate of air was increased over the stoichiometric need, but not as much as in the simulations of FIGS. 34A and 34B. In the simulation of FIG. 34C, the total gas was injected at 20,000 kg/day. This represents 2.1 times the stoichiometric amount of air needed to combust methane fuel.

As illustrated, the temperature of the inner tubing 3520 rose above 1,000° C. around the burner 3538 and steadily dropped to approximately 250° C. at 150 meters below the burner 3538. Similarly, the outer tubing 3510 reached 900° C. nearest the burner 3538, and then dropped non-linearly to approximately 250° C. at 150 meters below the burner 3538. The extreme temperature swings in FIG. 34C illustrate the preference for extra air flow to achieve optimal temperature maintenance throughout the wellbore.

FIG. 34D provides yet another graph charting depth in a wellbore versus temperature. Once again, the average temperatures inside and outside of the tubing 3520 are compared. More specifically, temperatures are compared between the downward air flow “A” and the upward flow of flue gas “FG.”

The depth in the wellbore is charted relative to the location of a burner downhole. In this wellbore, three burners are placed approximately 100 meters apart. Each burner was a 170 kW burner. This is a smaller burner than was used in the single burner simulations of FIGS. 34A, 34B, and 34C.

Insulation 3518 is assumed to be placed along the inner tubing 3520 below the uppermost burner. The insulation is assumed to be along the entire length of the tubing along the subsurface formation, and provides a heat transfer coefficient of 25 W/m₂° C. In areas along the tubing 3520 where there is no insulation, the overall heat transfer coefficient between the downward air “A” flow and the upward flue gas “FG” flow was 180 W/m² C.

To aid in the movement of heat from inside of the inner tubing 3520 to outside of the inner tubing 3520, the flow rate of air was increased. The total gas was injected at 40,000 kg/day. This represents 2.7 times the stoichiometric amount of air to combust methane fuel

As illustrated in FIG. 34D, the temperature of the inner tubing 3520 rose to approximately 650° C. at the depth of the first burner, and then quickly dropped to approximately 400° C. at a depth of 100 meters below the first burner. When the air hit the second burner, the temperature inside of the inner tubing 2920 again increased to just over 700° C. The temperature within the inner tubing 2920 decreased again to about 400° C. at a further depth of 100 meters below the second burner. This pattern was repeated at the third burner, with the inner tubing 2920 reaching just over 700° C. at the third burner and then dropping to about 400° C. at a further depth of 100 meters below the third burner.

Concerning the outer tubing 3510, the outer tubing 3510 reached a temperature of approximately 425° C. at the depth of the first burner, and then dropped to approximately 350° C. 50 meters below the first burner. Of interest, the temperature in the outer tubing 3510 then began to rise again until reaching an approximate temperature of 475° C. near the second burner. The temperature again dropped to about 350° C. before rising again to about 475° C. at the depth of the third burner.

The chart of FIG. 34D demonstrates that the use of multiple smaller burners within a heater well helps to maintain a relatively constant temperature within the piping 2910 adjacent the surrounding formation. Smaller burners means burners that are rated to have a lower power, that is, a lower energy output per unit of time, e.g., Watts or BTU/hour. The temperature in the casing 3510 (outside of the tubing 3520) stayed within a range of 350° C. to about 475° C. over a depth of 300 meters. This temperature range is above the temperature generally needed for the pyrolysis of oil shale. Along with FIG. 34B, FIG. 34D also demonstrates the efficacy of insulation along the tubing 3520 in providing a more uniform heat profile.

Using a heater well such as heater well 3200, a method for in situ heating of a targeted organic-rich rock formation is again provided herein. In one aspect, the method includes the steps of providing casing 2910 in a wellbore 2904 extending to a depth of the organic-rich rock formation 2905. The casing has a closed lower end 2912. A tubing 2920 is provided within the casing 2910. The tubing 2920 defines an annulus 2914 between the tubing 2920 and the surrounding casing 2910. The method further includes injecting air and a combustible fuel into the tubing 2920, and providing hardware in the tubing 2920 so as to cause the air and the combustible fuel to mix at substantially the depth of the organic-rich rock formation 2905 and in such a manner that a thermal conduction profile adjacent the wellbore 2904 along a selected portion of the organic-rich rock formation 2905 is substantially uniform. Preferably, the thermal conduction profile adjacent the wellbore 2904 along the selected portion of the organic-rich rock formation 2905 remains uniformly between about 300° C. and 750° C.

In one embodiment, such as the embodiment shown in FIG. 32, the hardware comprises a first tubular member 3230 residing within the tubing 2920 and extending to the selected portion of the organic-rich rock formation 2905. A first burner 3238 a is located at a first depth within the organic-rich rock formation 2905, and a second burner 3238 b is located at a second depth within the organic-rich rock formation 2905 that is lower than the first depth. Each burner 3238 a, 3238 b (and any others) are positioned along the first tubular member 3230. Preferably, the hardware further includes a first tubular cowl 3240 disposed around or immediately below the first burner 3238 a, and a second tubular cowl 3240 disposed around or immediately below the second burner 3238 b. The hardware also preferably comprises an insulation layer placed along an inner surface of the tubing 2920 proximate the first 3238 a and second 3238 b burners.

As shown in FIG. 32, the hardware in the heater well 3200 may also comprise a third burner 3238 c. A tubular cowl 3240 is also disposed around this burner 3238 c. In one aspect, the first burner 3238 a, the second burner 3238 b, and the third burner 3238 c are each separated by about 20 to 200 meters. Alternatively, the first burner, the second burner, and the third burner are each separated by about 20 to 200 meters. Alternatively, the first burner 3238 a, the second burner 3238 b, and the third burner 3238 c are each separated by about 40 to 150 meters, or by 60 to 120 meters.

Various size burners may be employed in the heater well 3200. For example, the burners may each supply about 0.5 to 4.0 kW of thermal energy per meter of formation to be heated or, alternatively, 1 to 3 kW/m. In one aspect, the burners each have an expander (not shown) below the orifice to reduce flow velocity of the combustible fuel “CF” prior to combustion.

In one embodiment, a portion of the tubing 2920 proximate the first depth is constructed from an alloy or metal having a higher maximum working temperature than a remaining portion of the tubing. In one aspect, the portion of the tubing having a higher maximum working temperature resides about 10 meters above the depth of a burner, and extends down to about 20 meters below the burner within the tubing 2920.

In one embodiment, the method further includes the step of directing “FG” generated from the first burner 3238 a and at least the second burner 3238 b up into the annulus 2924. In this embodiment, the method may also include monitoring a temperature of the flue gas “FG” at a point in the casing 2910 near the depth of the first burner 3238 a.

It is desirable to control the heat conducted into the formation 2905. Thus, in one embodiment the positions of the burners, the rate of injecting the combustible fuel, the rate of injecting the air, or combinations thereof, are specified so that the temperature of the flue gas “FG” traveling up the annulus 2924 is about 300° C. to 900° C. across a majority of the organic-rich rock formation 2905. More preferably, the temperature profile along the wellbore 2900 or 3200 into the formation 2905 remains fairly uniform between about 300° C. and 750° C. The rate of injecting the combustible fuel may be reduced over time to control the temperature as the formation warms.

In one embodiment, the combustible fuel is a fuel gas such as natural gas. The intensity of the burners 3238 is then controlled by adjusting the composition of the fuel gas. For instance, the natural gas may be diluted with added inert components. The added inert components may comprise at least one of carbon dioxide (CO₂) or nitrogen (N₂). Reducing flame intensity can lead to reduced NO_(x) generation.

The position of the uppermost burner 3238 a may also be adjusted. In one aspect, the first burner 3238 a is placed near the top of the targeted section of an organic-rich rock formation 2905. In another aspect, the first burner 3238 a is placed within 50 meters of the top of the targeted section of an organic-rich rock formation 2905. Alternatively still, the first burner 3238 a is placed within 20 meters of the top of the targeted section of an organic-rich rock formation 2905.

Various means may be used for injecting the combustible fuel into the first tubular member. In one aspect, the hardware further comprises at least one fuel line for delivering the injected fuel to the burners 3238. The at least one fuel line may comprise a single fuel line disposed primarily within the annulus 2924.

In one embodiment, the method further includes heating the oil shale in order to pyrolyze at least a portion of the oil shale into hydrocarbon fluids, the hydrocarbon fluids comprising gas, and producing the gas. In this embodiment, the combustible fuel may comprise the gas produced from the hydrocarbon fluids. This method may further include treating the hydrocarbon fluids in order to substantially remove H₂S from the gas before re-injecting the gas into the tubular member.

In one aspect, the positions of the burners, the rate of injecting the combustible fuel, the rate of injecting the air, or combinations thereof, are specified so that the temperature of the flue gas traveling up the annulus is about 300° C. to 750° C. across the selected portion of the organic-rich rock formation.

In another aspect, insulation 2918 is provided along the tubing 2920. The insulation 2918 is placed adjacent the burners 3238. Optionally, the insulation 2918 extends across the entire depth of the organic-rich rock formation 2905.

In the production of oil and gas resources, it may be desirable to use the produced hydrocarbons as a source of power for ongoing operations. This may be applied to the development of oil and gas resources from oil shale. Electrical power may be obtained from turbines that turn generators. It may be economically advantageous to power the gas turbines by utilizing produced gas from the field. However, such produced gas must be carefully controlled so not to damage the turbine, cause the turbine to misfire, or generate excessive pollutants (e.g., NO_(x)).

One source of problems for gas turbines is the presence of contaminants within the fuel. Contaminants include solids, water, heavy components present as liquids, and hydrogen sulfide. Additionally, the combustion behavior of the fuel is important. Combustion parameters to consider include heating value, specific gravity, adiabatic flame temperature, flammability limits, autoignition temperature, autoignition delay time, and flame velocity. Wobbe Index (WI) is often used as a key measure of fuel quality. WI is equal to the ratio of the lower heating value to the square root of the gas specific gravity. Control of the fuel's Wobbe Index to a target value and range of, for example, ±10% or ±20% can allow simplified turbine design and increased optimization of performance.

Fuel quality control may be useful for shale oil developments where the produced gas composition may change over the life of the field and where the gas typically has significant amounts of CO₂, CO, and H₂ in addition to light hydrocarbons. Commercial scale oil shale retorting is expected to produce a gas composition that changes with time.

Inert gases in the turbine fuel can increase power generation by increasing mass flow while maintaining a flame temperature in a desirable range. Moreover inert gases can lower flame temperature and thus reduce NO_(x) pollutant generation. Gas generated from oil shale maturation may have significant CO₂ content. Therefore, in certain embodiments of the production processes, the CO₂ content of the fuel gas is adjusted via separation or addition in the surface facilities to optimize turbine performance.

Achieving a certain hydrogen content for low-BTU fuels may also be desirable to achieve appropriate burn properties. In certain embodiments of the processes herein, the H₂ content of the fuel gas is adjusted via separation or addition in the surface facilities to optimize turbine performance. Adjustment of H₂ content in non-shale oil surface facilities utilizing low BTU fuels has been discussed in the patent literature (e.g., U.S. Pat. No. 6,684,644 and U.S. Pat. No. 6,858,049, the entire disclosures of which are hereby incorporated by reference).

The process of heating formation hydrocarbons within an organic-rich rock formation, for example, by pyrolysis, may generate fluids. The heat-generated fluids may include water which is vaporized within the formation. In addition, the action of heating kerogen produces pyrolysis fluids which tend to expand upon heating. The produced pyrolysis fluids may include not only water, but also, for example, hydrocarbons, oxides of carbon, ammonia, molecular nitrogen, and molecular hydrogen. Therefore, as temperatures within a heated portion of the formation increase, a pressure within the heated portion may also increase as a result of increased fluid generation, molecular expansion, and vaporization of water. Thus, some corollary exists between subsurface pressure in an oil shale formation and the fluid pressure generated during pyrolysis. This, in turn, indicates that formation pressure may be monitored to detect the progress of a kerogen conversion process.

The pressure within a heated portion of an organic-rich rock formation depends on other reservoir characteristics. These may include, for example, formation depth, distance from a heater well, a richness of the formation hydrocarbons within the organic-rich rock formation, the degree of heating, and/or a distance from a producer well.

It may be desirable for the developer of an oil shale field to monitor formation pressure during development. Pressure within a formation may be determined at a number of different locations. Such locations may include, but may not be limited to, at a wellhead and at varying depths within a wellbore. In some embodiments, pressure may be measured at a producer well. In an alternate embodiment, pressure may be measured at a heater well. In still another embodiment, pressure may be measured downhole of a dedicated monitoring well.

The process of heating an organic-rich rock formation to a pyrolysis temperature range not only will increase formation pressure, but will also increase formation permeability. The pyrolysis temperature range should be reached before substantial permeability has been generated within the organic-rich rock formation. An initial lack of permeability may prevent the transport of generated fluids from a pyrolysis zone within the formation. In this manner, as heat is initially transferred from a heater well to an organic-rich rock formation, a fluid pressure within the organic-rich rock formation may increase proximate to that heater well. Such an increase in fluid pressure may be caused by, for example, the generation of fluids during pyrolysis of at least some formation hydrocarbons in the formation.

Alternatively, pressure generated by expansion of pyrolysis fluids or other fluids generated in the formation may be allowed to increase. This assumes that an open path to a production well or other pressure sink does not yet exist in the formation. In one aspect, a fluid pressure may be allowed to increase to or above a lithostatic stress. In this instance, fractures in the hydrocarbon containing formation may form when the fluid pressure equals or exceeds the lithostatic stress. For example, fractures may form from a heater well to a production well. The generation of fractures within the heated portion may reduce pressure within the portion due to the production of produced fluids through a production well.

Once pyrolysis has begun within an organic-rich rock formation, fluid pressure may vary depending upon various factors. These include, for example, thermal expansion of hydrocarbons, generation of pyrolysis fluids, rate of conversion, and withdrawal of generated fluids from the formation. For example, as fluids are generated within the formation, fluid pressure within the pores may increase. Removal of generated fluids from the formation may then decrease the fluid pressure within the near wellbore region of the formation.

In certain embodiments, a mass of at least a portion of an organic-rich rock formation may be reduced due, for example, to pyrolysis of formation hydrocarbons and the production of hydrocarbon fluids from the formation. As such, the permeability and porosity of at least a portion of the formation may increase. Any in situ method that effectively produces oil and gas from oil shale will create permeability in what was originally a very low permeability rock. The extent to which this will occur is illustrated by the large amount of expansion that must be accommodated if fluids generated from kerogen are unable to flow. The concept is illustrated in FIG. 5.

FIG. 5 provides a bar chart comparing one ton of Green River oil shale before 50 and after 51 a simulated in situ, retorting process. The simulated process was carried out at 2,400 psi and 750° F. on oil shale having a total organic carbon content of 22 wt. % and a Fisher assay of 42 gallons/ton. Before the conversion, a total of 15.3 ft³ of rock matrix 52 existed. This matrix comprised 7.2 ft³ of mineral 53, i.e., dolomite, limestone, etc., and 8.1 ft³ of kerogen 54 imbedded within the shale. As a result of the conversion the material expanded to 26.1 ft³ 55. This represented 7.2 ft³ of mineral 56 (the same number as before the conversion), 6.6 ft³ of hydrocarbon liquid 57, 9.4 ft³ of hydrocarbon vapor 58, and 2.9 ft³ of coke 59. It can be seen that substantial volume expansion occurred during the conversion process. This, in turn, increases permeability of the rock structure.

In an embodiment, heating a portion of an organic-rich rock formation in situ to a pyrolysis temperature may increase permeability of the heated portion. For example, permeability may increase due to formation of thermal fractures within the heated portion caused by application of heat. As the temperature of the heated portion increases, water may be removed due to vaporization. The vaporized water may escape and/or be removed from the formation. In addition, permeability of the heated portion may also increase as a result of production of hydrocarbon fluids from pyrolysis of at least some of the formation hydrocarbons within the heated portion on a macroscopic scale.

Certain systems and methods described herein may be used to treat formation hydrocarbons in at least a portion of a relatively low permeability formation (e.g., in “tight” formations that contain formation hydrocarbons). Such formation hydrocarbons may be heated to pyrolyze at least some of the formation hydrocarbons in a selected zone of the formation. Heating may also increase the permeability of at least a portion of the selected zone. Hydrocarbon fluids generated from pyrolysis may be produced from the formation, thereby further increasing the formation permeability.

Permeability of a selected zone within the heated portion of the organic-rich rock formation may also rapidly increase while the selected zone is heated by conduction. For example, permeability of an impermeable organic-rich rock formation may be less than about 0.1 millidarcy before heating. In some embodiments, pyrolyzing at least a portion of organic-rich rock formation may increase permeability within a selected zone of the portion to greater than about 10 millidarcies, 100 millidarcies, 1 Darcy, 10 Darcies, 20 Darcies, or 50 Darcies. Therefore, a permeability of a selected zone of the portion may increase by a factor of more than about 10, 100, 1,000, 10,000, or 100,000. In one embodiment, the organic-rich rock formation has an initial total permeability less than 1 millidarcy, alternatively less than 0.1 or 0.01 millidarcies, before heating the organic-rich rock formation. In one embodiment, the organic-rich rock formation has a post heating total permeability of greater than 1 millidarcy, alternatively, greater than 10, 50 or 100 millidarcies, after heating the organic-rich rock formation.

In connection with heating the organic-rich rock formation, the organic-rich rock formation may optionally be fractured to aid heat transfer or hydrocarbon fluid production. In one instance, fracturing may be accomplished naturally by creating thermal fractures within the formation through application of heat. Thermal fracture formation is caused by thermal expansion of the rock and fluids and by chemical expansion of kerogen transforming into oil and gas. Thermal fracturing can occur both in the immediate region undergoing heating, and in cooler neighboring regions. The thermal fracturing in the neighboring regions is due to propagation of fractures and tension stresses developed due to the expansion in the hotter zones. Thus, by both heating the organic-rich rock and transforming the kerogen to oil and gas, the permeability is increased not only from fluid formation and vaporization, but also via thermal fracture formation. The increased permeability aids fluid flow within the formation and production of the hydrocarbon fluids generated from the kerogen.

In addition, a process known as hydraulic fracturing may be used. Hydraulic fracturing is a process known in the art of oil and gas recovery where a fracture fluid is pressurized within the wellbore above the fracture pressure of the formation, thus developing fracture planes within the formation to relieve the pressure generated within the wellbore. Hydraulic fractures may be used to create additional permeability and/or be used to provide an extended geometry for a heater well. The WO 2005/010320 patent publication incorporated above describes one such method.

In connection with the production of hydrocarbons from a rock matrix, particularly those of shallow depth, a concern may exist with respect to earth subsidence. This is particularly true in the in situ heating of organic-rich rock where a portion of the matrix itself is thermally converted and removed. Initially, the formation may contain formation hydrocarbons in solid form, such as, for example, kerogen. The formation may also initially contain water-soluble minerals. Initially, the formation may also be substantially impermeable to fluid flow.

The in situ heating of the matrix pyrolyzes at least a portion of the formation hydrocarbons to create hydrocarbon fluids. This, in turn, creates permeability within a matured (pyrolyzed) organic-rich rock zone in the organic-rich rock formation. The combination of pyrolyzation and increased permeability permits hydrocarbon fluids to be produced from the formation. At the same time, the loss of supporting matrix material also creates the potential for subsidence relative to the earth surface.

In some instances, subsidence is sought to be minimized in order to avoid environmental or hydrogeological impact. In this respect, changing the contour and relief of the earth surface, even by a few inches, can change runoff patterns, affect vegetation patterns, and impact watersheds. In addition, subsidence has the potential of damaging production or heater wells formed in a production area. Such subsidence can create damaging hoop and compressional stresses on wellbore casings, cement jobs, and equipment downhole.

In order to avoid or minimize subsidence, it is proposed to leave selected portions of the formation hydrocarbons substantially unpyrolyzed. This serves to preserve one or more unmatured, organic-rich rock zones. In some embodiments, the unmatured organic-rich rock zones may be shaped as substantially vertical pillars extending through a substantial portion of the thickness of the organic-rich rock formation.

The heating rate and distribution of heat within the formation may be designed and implemented to leave sufficient unmatured pillars to prevent subsidence. In one aspect, heat injection wellbores are formed in a pattern such that untreated pillars of oil shale are left therebetween to support the overburden and prevent subsidence.

It is preferred that thermal recovery of oil and gas be conducted before any solution mining of nahcolite or other water-soluble minerals present in the formation. Solution mining can generate large voids in a rock formation and collapse breccias in an oil shale development area. These voids and brecciated zones may pose problems for in situ and mining recovery of oil shale, further increasing the utility of supporting pillars.

In some embodiments, compositions and properties of the hydrocarbon fluids produced by an in situ conversion process may vary depending on, for example, conditions within an organic-rich rock formation. Controlling heat and/or heating rates of a selected section in an organic-rich rock formation may increase or decrease production of selected produced fluids.

In one embodiment, operating conditions may be determined by measuring at least one property of the organic-rich rock formation. The measured properties may be input into a computer executable program. At least one property of the produced fluids selected to be produced from the formation may also be input into the computer executable program. The program may be operable to determine a set of operating conditions from at least the one or more measured properties. The program may also be configured to determine the set of operating conditions from at least one property of the selected produced fluids. In this manner, the determined set of operating conditions may be configured to increase production of selected produced fluids from the formation.

Certain heater well embodiments may include an operating system that is coupled to any of the heater wells such as by insulated conductors or other types of wiring. The operating system may be configured to interface with the heater well. The operating system may receive a signal (e.g., an electromagnetic signal) from a heater that is representative of a temperature distribution of the heater well. Additionally, the operating system may be further configured to control the heater well, either locally or remotely. For example, the operating system may alter a temperature of the heater well by altering a parameter of equipment coupled to the heater well. Therefore, the operating system may monitor, alter, and/or control the heating of at least a portion of the formation.

In some embodiments, a heater well may be turned down and/or off after an average temperature in a formation may have reached a selected temperature. Turning down and/or off the heater well may reduce input energy costs, substantially inhibit overheating of the formation, and allow heat to substantially transfer into colder regions of the formation.

Temperature (and average temperatures) within a heated organic-rich rock formation may vary, depending on, for example, proximity to a heater well, thermal conductivity and thermal diffusivity of the formation, type of reaction occurring, type of formation hydrocarbon, and the presence of water within the organic-rich rock formation. At points in the field where monitoring wells are established, temperature measurements may be taken directly in the wellbore. Further, at heater wells the temperature of the immediately surrounding formation is fairly well understood. However, it is desirable to interpolate temperatures to points in the formation intermediate temperature sensors and heater wells.

In accordance with one aspect of the production processes of the present inventions, a temperature distribution within the organic-rich rock formation may be computed using a numerical simulation model. The numerical simulation model may calculate a subsurface temperature distribution through interpolation of known data points and assumptions of formation conductivity. In addition, the numerical simulation model may be used to determine other properties of the formation under the assessed temperature distribution. For example, the various properties of the formation may include, but are not limited to, permeability of the formation.

The numerical simulation model may also include assessing various properties of a fluid formed within an organic-rich rock formation under the assessed temperature distribution. For example, the various properties of a formed fluid may include, but are not limited to, a cumulative volume of a fluid formed in the formation, fluid viscosity, fluid density, and a composition of the fluid formed in the formation. Such a simulation may be used to assess the performance of a commercial-scale operation or small-scale field experiment. For example, a performance of a commercial-scale development may be assessed based on, but not limited to, a total volume of product that may be produced from a research-scale operation.

Some embodiments include producing at least a portion of the hydrocarbon fluids from the organic-rich rock formation. The hydrocarbon fluids may be produced through production wells. Production wells may be cased or uncased wells and drilled and completed through methods known in the art.

Some embodiments further include producing a production fluid from the organic-rich rock formation where the production fluid contains the hydrocarbon fluids and an aqueous fluid. The aqueous fluid may contain water-soluble minerals and/or migratory contaminant species. In such case, the production fluid may be separated into a hydrocarbon stream and an aqueous stream at a surface facility. Thereafter the water-soluble minerals and/or migratory contaminant species may be recovered from the aqueous stream. This embodiment may be combined with any of the other aspects of the invention discussed herein.

The produced hydrocarbon fluids may include a pyrolysis oil component (or condensable component) and a pyrolysis gas component (or non-condensable component). Condensable hydrocarbons produced from the formation will typically include paraffins, cycloalkanes, mono-aromatics, and di-aromatics as components. Such condensable hydrocarbons may also include other components such as tri-aromatics and other hydrocarbon species.

In certain embodiments, a majority of the hydrocarbons in the produced fluid may have a carbon number of less than approximately 25. Alternatively, less than about 15 weight % of the hydrocarbons in the fluid may have a carbon number greater than approximately 25. The non-condensable hydrocarbons may include, but are not limited to, hydrocarbons having carbon numbers less than 5.

In certain embodiments, the API gravity of the condensable hydrocarbons in the produced fluid may be approximately 20 or above (e.g., 25, 30, 40, 50, etc.). In certain embodiments, the hydrogen to carbon atomic ratio in produced fluid may be at least approximately 1.7 (e.g., 1.8, 1.9, etc.).

One embodiment of the invention includes an in situ method of producing hydrocarbon fluids with improved properties from an organic-rich rock formation. Applicants have surprisingly discovered that the quality of the hydrocarbon fluids produced from in situ heating and pyrolysis of an organic-rich rock formation may be improved by selecting sections of the organic-rich rock formation with higher lithostatic stress for in situ heating and pyrolysis.

The method may include in situ heating of a section of the organic-rich rock formation that has a high lithostatic stress to form hydrocarbon fluids with improved properties. The method may include creating the hydrocarbon fluid by pyrolysis of a solid hydrocarbon and/or a heavy hydrocarbon present in the organic-rich rock formation. Embodiments may include the hydrocarbon fluid being partially, predominantly or substantially completely created by pyrolysis of the solid hydrocarbon and/or heavy hydrocarbon present in the organic-rich rock formation. The method may include heating the section of the organic-rich rock formation by any method, including any of the methods described herein. For example, the method may include heating the section of the organic-rich rock formation by electrical resistance heating. Further, the method may include heating the section of the organic-rich rock formation through use of a heated heat transfer fluid. The method may include heating the section of the organic-rich rock formation to above 270° C. Alternatively, the method may include heating the section of the organic-rich rock formation between 270° C. and 500° C.

The method may include heating in situ a section of the organic-rich rock formation having a lithostatic stress greater than 200 psi and producing a hydrocarbon fluid from the heated section of the organic-rich rock formation. In alternative embodiments, the heated section of the organic-rich rock formation may have a lithostatic stress greater than 400 psi. In alternative embodiments, the heated section of the organic-rich rock formation may have a lithostatic stress greater than 800 psi, greater than 1,000 psi, greater than 1,200 psi, greater than 1,500 psi or greater than 2,000 psi. Applicants have found that in situ heating and pyrolysis of organic-rich rock formations with increasing amounts of stress lead to the production of hydrocarbon fluids with improved properties.

The lithostatic stress of a section of an organic-rich formation can normally be estimated by recognizing that it will generally be equal to the weight of the rocks overlying the formation. The density of the overlying rocks can be expressed in units of psi/ft. Generally, this value will fall between 0.8 and 1.1 psi/ft and can often be approximated as 0.9 psi/ft. As a result the lithostatic stress of a section of an organic-rich formation can be estimated by multiplying the depth of the organic-rich rock formation interval by 0.9 psi/ft. Thus the lithostatic stress of a section of an organic-rich formation occurring at about 1,000 ft can be estimated to be about (0.9 psi/ft) multiplied by (1,000 ft) or about 900 psi. If a more precise estimate of lithostatic stress is desired the density of overlying rocks can be measured using wireline logging techniques or by making laboratory measurements on samples recovered from coreholes. The method may include heating a section of the organic-rich rock formation that is located at a depth greater than 200 ft below the earth's surface. Alternatively, the method may include heating a section of the organic-rich rock formation that is located at a depth greater than 500 ft below the earth's surface, greater than 1,000 ft below the earth's surface, greater than 1,200 ft below the earth's surface, greater than 1,500 ft below the earth's surface, or greater than 2,000 ft below the earth's surface.

The organic-rich rock formation may be, for example, a heavy hydrocarbon formation or a solid hydrocarbon formation. Particular examples of such formations may include an oil shale formation, a tar sands formation or a coal formation. Particular formation hydrocarbons present in such formations may include oil shale, kerogen, coal, and/or bitumen.

The hydrocarbon fluid produced from the organic-rich rock formation may include both a condensable hydrocarbon portion (e.g. liquid) and a non-condensable hydrocarbon portion (e.g. gas). The hydrocarbon fluid may additionally be produced together with non-hydrocarbon fluids. Exemplary non-hydrocarbon fluids include, for example, water, carbon dioxide, hydrogen sulfide, hydrogen, ammonia, and/or carbon monoxide.

The condensable hydrocarbon portion of the hydrocarbon fluid may be a fluid present within different locations associated with an organic-rich rock development project. For example, the condensable hydrocarbon portion of the hydrocarbon fluid may be a fluid present within a production well that is in fluid communication with the organic-rich rock formation. The production well may serve as a device for withdrawing the produced hydrocarbon fluids from the organic-rich rock formation. Alternatively, the condensable hydrocarbon portion may be a fluid present within processing equipment adapted to process hydrocarbon fluids produced from the organic-rich rock formation. Exemplary processing equipment is described herein. Alternatively, the condensable hydrocarbon portion may be a fluid present within a fluid storage vessel. Fluid storage vessels may include, for example, fluid storage tanks with fixed or floating roofs, knock-out vessels, and other intermediate, temporary or product storage vessels. Alternatively, the condensable hydrocarbon portion may be a fluid present within a fluid transportation pipeline. A fluid transportation pipeline may include, for example, piping from production wells to processing equipment or fluid storage vessels, piping from processing equipment to fluid storage vessels, or pipelines associated with collection or transportation of fluids to or from intermediate or centralized storage locations.

The following discussion of FIGS. 7-16 concerns data obtained in Examples 1-5 which are discussed in the section labeled “Experiments”. The data was obtained through the experimental procedures, gas and liquid sample collection procedures, hydrocarbon gas sample gas chromatography (GC) analysis methodology, gas sample GC peak integration methodology, gas sample GC peak identification methodology, whole oil gas chromatography (WOGC) analysis methodology, whole oil gas chromatography (WOGC) peak integration methodology, whole oil gas chromatography (WOGC) peak identification methodology, and pseudo component analysis methodology discussed in the Experiments section. For clarity, when referring to gas chromatography chromatograms of hydrocarbon gas samples, graphical data is provided for one unstressed experiment through Example 1, two 400 psi stressed experiments through Examples 2 and 3, and two 1,000 psi stressed experiments through Examples 4 and 5. When referring to whole oil gas chromatography (WOGC) chromatograms of liquid hydrocarbon samples, graphical data is provided for one unstressed experiment through Example 1, one 400 psi stressed experiments through Example 3, and one 1,000 psi stressed experiment through Example 4.

FIG. 7 is a graph of the weight percent of each carbon number pseudo component occurring from C6 to C38 for each of the three stress levels tested and analyzed in the laboratory experiments discussed herein. The pseudo component weight percentages were obtained through the experimental procedures, liquid sample collection procedures, whole oil gas chromatography (WOGC) analysis methodology, whole oil gas chromatography (WOGC) peak identification and integration methodology, and pseudo component analysis methodology discussed in the Experiments section. For clarity, the pseudo component weight percentages are taken as a percentage of the entire C3 to pseudo C38 whole oil gas chromatography areas and calculated weights. Thus the graphed C6 to C38 weight percentages do not include the weight contribution of the associated gas phase product from any of the experiments which was separately treated. Further, the graphed weight percentages do not include the weight contribution of any liquid hydrocarbon compounds heavier than (i.e. having a longer retention time than) the C38 pseudo component. The y-axis 2000 represents the concentration in terms of weight percent of each C6 to C38 pseudo component in the liquid phase. The x-axis 2001 contains the identity of each hydrocarbon pseudo component from C6 to C38. The data points occurring on line 2002 represent the weight percent of each C6 to C38 pseudo component for the unstressed experiment of Example 1. The data points occurring on line 2003 represent the weight percent of each C6 to C38 pseudo component for the 400 psi stressed experiment of Example 3. While the data points occurring on line 2004 represent the weight percent of each C6 to C38 pseudo component for the 1,000 psi stressed experiment of Example 4. From FIG. 7 it can be seen that the hydrocarbon liquid produced in the unstressed experiment, represented by data points on line 2002, contains a lower weight percentage of lighter hydrocarbon components in the C8 to C17 pseudo component range and a greater weight percentage of heavier hydrocarbon components in the C20 to C29 pseudo component range, both as compared to the 400 psi stress experiment hydrocarbon liquid and the 1,000 psi stress experiment hydrocarbon liquid. Looking now at the data points occurring on line 2003, it is apparent that the intermediate level 400 psi stress experiment produced a hydrocarbon liquid having C8 to C17 pseudo component concentrations between the unstressed experiment represented by line 2002 and the 1,000 psi stressed experiment represented by line 2004. It is noted that the C17 pseudo component data for both the 400 psi and 1,000 psi stressed experiments are about equal. Further, it is apparent that the weight percentage of heavier hydrocarbon components in the C20 to C29 pseudo component range for the intermediate stress level experiment represented by line 2003 falls between the unstressed experiment (Line 2002) hydrocarbon liquid and the 1,000 psi stress experiment (Line 2004) hydrocarbon liquid. Lastly, it is apparent that the high level 1,000 psi stress experiment produced a hydrocarbon liquid having C8 to C17 pseudo component concentrations greater than both the unstressed experiment represented by line 2002 and the 400 psi stressed experiment represented by line 2003. Further, it is apparent that the weight percentage of heavier hydrocarbon components in the C20 to C29 pseudo component range for the high level stress experiment represented by line 2004 are less than both the unstressed experiment (Line 2002) hydrocarbon liquid and the 400 psi stress experiment (Line 2003) hydrocarbon liquid. Thus pyrolyzing oil shale under increasing levels of lithostatic stress appears to produce hydrocarbon liquids having increasingly lighter carbon number distributions.

FIG. 8 is a graph of the weight percent ratios of each carbon number pseudo component occurring from C6 to C38 as compared to the C20 pseudo component for each of the three stress levels tested and analyzed in the laboratory experiments discussed herein. The pseudo component weight percentages were obtained as described for FIG. 7. The y-axis 2020 represents the weight ratio of each C6 to C38 pseudo component compared to the C20 pseudo component in the liquid phase. The x-axis 2021 contains the identity of each hydrocarbon pseudo component ratio from C6/C20 to C38/C20. The data points occurring on line 2022 represent the weight ratio of each C6 to C38 pseudo component to C20 pseudo component for the unstressed experiment of Example 1. The data points occurring on line 2023 represent the weight ratio of each C6 to C38 pseudo component to C20 pseudo component for the 400 psi stressed experiment of Example 3. While the data points occurring on line 2024 represent the weight ratio of each C6 to C38 pseudo component to C20 pseudo component for the 1,000 psi stressed experiment of Example 4. From FIG. 8 it can be seen that the hydrocarbon liquid produced in the unstressed experiment, represented by data points on line 2022, contains a lower weight percentage of lighter hydrocarbon components in the C8 to C18 pseudo component range as compared to the C20 pseudo component and a greater weight percentage of heavier hydrocarbon components in the C22 to C29 pseudo component range as compared to the C20 pseudo component, both as compared to the 400 psi stress experiment hydrocarbon liquid and the 1,000 psi stress experiment hydrocarbon liquid. Looking now at the data points occurring on line 2023, it is apparent that the intermediate level 400 psi stress experiment produced a hydrocarbon liquid having C8 to C18 pseudo component concentrations as compared to the C20 pseudo component between the unstressed experiment represented by line 2022 and the 1,000 psi stressed experiment represented by line 2024. Further, it is apparent that the weight percentage of heavier hydrocarbon components in the C22 to C29 pseudo component range as compared to the C20 pseudo component for the intermediate stress level experiment represented by line 2023 falls between the unstressed experiment (Line 2022) hydrocarbon liquid and the 1,000 psi stress experiment (Line 2024) hydrocarbon liquid. Lastly, it is apparent that the high level 1,000 psi stress experiment produced a hydrocarbon liquid having C8 to C18 pseudo component concentrations as compared to the C20 pseudo component greater than both the unstressed experiment represented by line 2022 and the 400 psi stressed experiment represented by line 2023. Further, it is apparent that the weight percentage of heavier hydrocarbon components in the C22 to C29 pseudo component range as compared to the C20 pseudo component for the high level stress experiment represented by line 2024 are less than both the unstressed experiment (Line 2022) hydrocarbon liquid and the 400 psi stress experiment (Line 2023) hydrocarbon liquid. This analysis further supports the relationship that pyrolyzing oil shale under increasing levels of lithostatic stress produces hydrocarbon liquids having increasingly lighter carbon number distributions.

FIG. 9 is a graph of the weight percent ratios of each carbon number pseudo component occurring from C6 to C38 as compared to the C25 pseudo component for each of the three stress levels tested and analyzed in the laboratory experiments discussed herein. The pseudo component weight percentages were obtained as described for FIG. 7. The y-axis 2040 represents the weight ratio of each C6 to C38 pseudo component compared to the C25 pseudo component in the liquid phase. The x-axis 2041 contains the identity of each hydrocarbon pseudo component ratio from C6/C25 to C38/C25. The data points occurring on line 2042 represent the weight ratio of each C6 to C38 pseudo component to C25 pseudo component for the unstressed experiment of Example 1. The data points occurring on line 2043 represent the weight ratio of each C6 to C38 pseudo component to C25 pseudo component for the 400 psi stressed experiment of Example 3. While the data points occurring on line 2044 represent the weight ratio of each C6 to C38 pseudo component to C25 pseudo component for the 1,000 psi stressed experiment of Example 4. From FIG. 9 it can be seen that the hydrocarbon liquid produced in the unstressed experiment, represented by data points on line 2042, contains a lower weight percentage of lighter hydrocarbon components in the C7 to C24 pseudo component range as compared to the C25 pseudo component and a greater weight percentage of heavier hydrocarbon components in the C26 to C29 pseudo component range as compared to the C25 pseudo component, both as compared to the 400 psi stress experiment hydrocarbon liquid and the 1,000 psi stress experiment hydrocarbon liquid. Looking now at the data points occurring on line 2043, it is apparent that the intermediate level 400 psi stress experiment produced a hydrocarbon liquid having C7 to C24 pseudo component concentrations as compared to the C25 pseudo component between the unstressed experiment represented by line 2042 and the 1,000 psi stressed experiment represented by line 2044. Further, it is apparent that the weight percentage of heavier hydrocarbon components in the C26 to C29 pseudo component range as compared to the C25 pseudo component for the intermediate stress level experiment represented by line 2043 falls between the unstressed experiment (Line 2042) hydrocarbon liquid and the 1,000 psi stress experiment (Line 2044) hydrocarbon liquid. Lastly, it is apparent that the high level 1,000 psi stress experiment produced a hydrocarbon liquid having C7 to C24 pseudo component concentrations as compared to the C25 pseudo component greater than both the unstressed experiment represented by line 2042 and the 400 psi stressed experiment represented by line 2043. Further, it is apparent that the weight percentage of heavier hydrocarbon components in the C26 to C29 pseudo component range as compared to the C25 pseudo component for the high level stress experiment represented by line 2044 are less than both the unstressed experiment (Line 2042) hydrocarbon liquid and the 400 psi stress experiment (Line 2043) hydrocarbon liquid. This analysis further supports the relationship that pyrolyzing oil shale under increasing levels of lithostatic stress produces hydrocarbon liquids having increasingly lighter carbon number distributions.

FIG. 10 is a graph of the weight percent ratios of each carbon number pseudo component occurring from C6 to C38 as compared to the C29 pseudo component for each of the three stress levels tested and analyzed in the laboratory experiments discussed herein. The pseudo component weight percentages were obtained as described for FIG. 7. The y-axis 2060 represents the weight ratio of each C6 to C38 pseudo component compared to the C29 pseudo component in the liquid phase. The x-axis 2061 contains the identity of each hydrocarbon pseudo component ratio from C6/C29 to C38/C29. The data points occurring on line 2062 represent the weight ratio of each C6 to C38 pseudo component to C29 pseudo component for the unstressed experiment of Example 1. The data points occurring on line 2063 represent the weight ratio of each C6 to C38 pseudo component to C29 pseudo component for the 400 psi stressed experiment of Example 3. While the data points occurring on line 2064 represent the weight ratio of each C6 to C38 pseudo component to C29 pseudo component for the 1,000 psi stressed experiment of Example 4. From FIG. 10 it can be seen that the hydrocarbon liquid produced in the unstressed experiment, represented by data points on line 2062, contains a lower weight percentage of lighter hydrocarbon components in the C6 to C28 pseudo component range as compared to the C29 pseudo component, both as compared to the 400 psi stress experiment hydrocarbon liquid and the 1,000 psi stress experiment hydrocarbon liquid. Looking now at the data points occurring on line 2063, it is apparent that the intermediate level 400 psi stress experiment produced a hydrocarbon liquid having C6 to C28 pseudo component concentrations as compared to the C29 pseudo component between the unstressed experiment represented by line 2062 and the 1,000 psi stressed experiment represented by line 2064. Lastly, it is apparent that the high level 1,000 psi stress experiment produced a hydrocarbon liquid having C6 to C28 pseudo component concentrations as compared to the C29 pseudo component greater than both the unstressed experiment represented by line 2062 and the 400 psi stressed experiment represented by line 2063. This analysis further supports the relationship that pyrolyzing oil shale under increasing levels of lithostatic stress produces hydrocarbon liquids having increasingly lighter carbon number distributions.

FIG. 11 is a graph of the weight percent of normal alkane hydrocarbon compounds occurring from the normal-C6 alkane to the normal-C38 alkane for each of the three stress levels tested and analyzed in the laboratory experiments discussed herein. The normal alkane compound weight percentages were obtained as described for FIG. 7, except that each individual normal alkane compound peak area integration was used to determine each respective normal alkane compound weight percentage. For clarity, the normal alkane hydrocarbon weight percentages are taken as a percentage of the entire C3 to pseudo C38 whole oil gas chromatography areas and calculated weights as used in the pseudo compound data presented in FIG. 7. The y-axis 2080 represents the concentration in terms of weight percent of each normal-C6 to normal-C38 compound found in the liquid phase. The x-axis 2081 contains the identity of each normal alkane hydrocarbon compound from normal-C6 to normal-C38. The data points occurring on line 2082 represent the weight percent of each normal-C6 to normal-C38 hydrocarbon compound for the unstressed experiment of Example 1. The data points occurring on line 2083 represent the weight percent of each normal-C6 to normal-C38 hydrocarbon compound for the 400 psi stressed experiment of Example 3. While the data points occurring on line 2084 represent the weight percent of each normal-C6 to normal-C38 hydrocarbon compound for the 1,000 psi stressed experiment of Example 4. From FIG. 11 it can be seen that the hydrocarbon liquid produced in the unstressed experiment, represented by data points on line 2082, contains a greater weight percentage of hydrocarbon compounds in the normal-C12 to normal-C30 compound range, both as compared to the 400 psi stress experiment hydrocarbon liquid and the 1,000 psi stress experiment hydrocarbon liquid. Looking now at the data points occurring on line 2083, it is apparent that the intermediate level 400 psi stress experiment produced a hydrocarbon liquid having normal-C12 to normal-C30 compound concentrations between the unstressed experiment represented by line 2082 and the 1,000 psi stressed experiment represented by line 2084. Lastly, it is apparent that the high level 1,000 psi stress experiment produced a hydrocarbon liquid having normal-C12 to normal-C30 compound concentrations less than both the unstressed experiment represented by line 2082 and the 400 psi stressed experiment represented by line 2083. Thus pyrolyzing oil shale under increasing levels of lithostatic stress appears to produce hydrocarbon liquids having lower concentrations of normal alkane hydrocarbons.

FIG. 12 is a graph of the weight percent of normal alkane hydrocarbon compounds occurring from normal-C6 to normal-C38 as compared to the normal-C20 hydrocarbon compound for each of the three stress levels tested and analyzed in the laboratory experiments discussed herein. The normal compound weight percentages were obtained as described for FIG. 11. The y-axis 3000 represents the concentration in terms of weight ratio of each normal-C6 to normal-C38 compound as compared to the normal-C20 compound found in the liquid phase. The x-axis 3001 contains the identity of each normal alkane hydrocarbon compound ratio from normal-C6/normal-C20 to normal-C38/normal-C20. The data points occurring on line 3002 represent the weight ratio of each normal-C6 to normal-C38 hydrocarbon compound as compared to the normal-C20 compound for the unstressed experiment of Example 1. The data points occurring on line 3003 represent the weight ratio of each normal-C6 to normal-C38 hydrocarbon compound as compared to the normal-C20 compound for the 400 psi stressed experiment of Example 3. While the data points occurring on line 3004 represent the weight ratio of each normal-C6 to normal-C38 hydrocarbon compound as compared to the normal-C20 compound for the 1,000 psi stressed experiment of Example 4. From FIG. 12 it can be seen that the hydrocarbon liquid produced in the unstressed experiment, represented by data points on line 3002, contains a lower weight percentage of lighter normal alkane hydrocarbon components in the normal-C6 to normal-C17 compound range as compared to the normal-C20 compound and a greater weight percentage of heavier hydrocarbon components in the normal-C22 to normal-C34 compound range as compared to the normal-C20 compound, both as compared to the 400 psi stress experiment hydrocarbon liquid and the 1,000 psi stress experiment hydrocarbon liquid. Looking now at the data points occurring on line 3003, it is apparent that the intermediate level 400 psi stress experiment produced a hydrocarbon liquid having normal-C6 to normal-C17 compound concentrations as compared to the normal-C20 compound between the unstressed experiment represented by line 3002 and the 1,000 psi stressed experiment represented by line 3004. Further, it is apparent that the weight percentage of heavier hydrocarbon components in the normal-C22 to normal-C34 compound range as compared to the normal-C20 compound for the intermediate stress level experiment represented by line 3003 falls between the unstressed experiment (Line 3002) hydrocarbon liquid and the 1,000 psi stress experiment (Line 3004) hydrocarbon liquid. Lastly, it is apparent that the high level 1,000 psi stress experiment produced a hydrocarbon liquid having normal-C6 to normal-C17 compound concentrations as compared to the normal-C20 compound greater than both the unstressed experiment represented by line 3002 and the 400 psi stressed experiment represented by line 3003. Further, it is apparent that the weight percentage of heavier hydrocarbon components in the normal-C22 to normal-C34 compound range as compared to the normal-C20 compound for the high level stress experiment represented by line 3004 are less than both the unstressed experiment (Line 3002) hydrocarbon liquid and the 400 psi stress experiment (Line 3003) hydrocarbon liquid. This analysis further supports the relationship that pyrolyzing oil shale under increasing levels of lithostatic stress produces hydrocarbon liquids having lower concentrations of normal alkane hydrocarbons.

FIG. 13 is a graph of the weight percent of normal alkane hydrocarbon compounds occurring from normal-C6 to normal-C38 as compared to the normal-C25 hydrocarbon compound for each of the three stress levels tested and analyzed in the laboratory experiments discussed herein. The normal compound weight percentages were obtained as described for FIG. 11. The y-axis 3020 represents the concentration in terms of weight ratio of each normal-C6 to normal-C38 compound as compared to the normal-C25 compound found in the liquid phase. The x-axis 3021 contains the identity of each normal alkane hydrocarbon compound ratio from normal-C6/normal-C25 to normal-C38/normal-C25. The data points occurring on line 3022 represent the weight ratio of each normal-C6 to normal-C38 hydrocarbon compound as compared to the normal-C25 compound for the unstressed experiment of Example 1. The data points occurring on line 3023 represent the weight ratio of each normal-C6 to normal-C38 hydrocarbon compound as compared to the normal-C25 compound for the 400 psi stressed experiment of Example 3. While the data points occurring on line 3024 represent the weight ratio of each normal-C6 to normal-C38 hydrocarbon compound as compared to the normal-C25 compound for the 1,000 psi stressed experiment of Example 4. From FIG. 13 it can be seen that the hydrocarbon liquid produced in the unstressed experiment, represented by data points on line 3022, contains a lower weight percentage of lighter normal alkane hydrocarbon components in the normal-C6 to normal-C24 compound range as compared to the normal-C25 compound and a greater weight percentage of heavier hydrocarbon components in the normal-C26 to normal-C30 compound range as compared to the normal-C25 compound, both as compared to the 400 psi stress experiment hydrocarbon liquid and the 1,000 psi stress experiment hydrocarbon liquid. Looking now at the data points occurring on line 3023, it is apparent that the intermediate level 400 psi stress experiment produced a hydrocarbon liquid having normal-C6 to normal-C24 compound concentrations as compared to the normal-C25 compound between the unstressed experiment represented by line 3022 and the 1,000 psi stressed experiment represented by line 3024. Further, it is apparent that the weight percentage of heavier hydrocarbon components in the normal-C26 to normal-C30 compound range as compared to the normal-C25 compound for the intermediate stress level experiment represented by line 3023 falls between the unstressed experiment (Line 3022) hydrocarbon liquid and the 1,000 psi stress experiment (Line 3024) hydrocarbon liquid. Lastly, it is apparent that the high level 1,000 psi stress experiment produced a hydrocarbon liquid having normal-C6 to normal-C24 compound concentrations as compared to the normal-C25 compound greater than both the unstressed experiment represented by line 3022 and the 400 psi stressed experiment represented by line 3023. Further, it is apparent that the weight percentage of heavier hydrocarbon components in the normal-C26 to normal-C30 compound range as compared to the normal-C25 compound for the high level stress experiment represented by line 3024 are less than both the unstressed experiment (Line 3022) hydrocarbon liquid and the 400 psi stress experiment (Line 3023) hydrocarbon liquid. This analysis further supports the relationship that pyrolyzing oil shale under increasing levels of lithostatic stress produces hydrocarbon liquids having lower concentrations of normal alkane hydrocarbons.

FIG. 14 is a graph of the weight percent of normal alkane hydrocarbon compounds occurring from normal-C6 to normal-C38 as compared to the normal-C29 hydrocarbon compound for each of the three stress levels tested and analyzed in the laboratory experiments discussed herein. The normal compound weight percentages were obtained as described for FIG. 11. The y-axis 3040 represents the concentration in terms of weight ratio of each normal-C6 to normal-C38 compound as compared to the normal-C29 compound found in the liquid phase. The x-axis 3041 contains the identity of each normal alkane hydrocarbon compound ratio from normal-C6/normal-C29 to normal-C38/normal-C29. The data points occurring on line 3042 represent the weight ratio of each normal-C6 to normal-C38 hydrocarbon compound as compared to the normal-C29 compound for the unstressed experiment of Example 1. The data points occurring on line 3043 represent the weight ratio of each normal-C6 to normal-C38 hydrocarbon compound as compared to the normal-C29 compound for the 400 psi stressed experiment of Example 3. While the data points occurring on line 3044 represent the weight ratio of each normal-C6 to normal-C38 hydrocarbon compound as compared to the normal-C29 compound for the 1,000 psi stressed experiment of Example 4. From FIG. 14 it can be seen that the hydrocarbon liquid produced in the unstressed experiment, represented by data points on line 3042, contains a lower weight percentage of lighter normal alkane hydrocarbon components in the normal-C6 to normal-C26 compound range as compared to the normal-C29 compound, both as compared to the 400 psi stress experiment hydrocarbon liquid and the 1,000 psi stress experiment hydrocarbon liquid. Looking now at the data points occurring on line 3043, it is apparent that the intermediate level 400 psi stress experiment produced a hydrocarbon liquid having normal-C6 to normal-C26 compound concentrations as compared to the normal-C29 compound between the unstressed experiment represented by line 3042 and the 1,000 psi stressed experiment represented by line 3044. Lastly, it is apparent that the high level 1,000 psi stress experiment produced a hydrocarbon liquid having normal-C6 to normal-C26 compound concentrations as compared to the normal-C29 compound greater than both the unstressed experiment represented by line 3042 and the 400 psi stressed experiment represented by line 3043. This analysis further supports the relationship that pyrolyzing oil shale under increasing levels of lithostatic stress produces hydrocarbon liquids having lower concentrations of normal alkane hydrocarbons.

FIG. 15 is a graph of the weight ratio of normal alkane hydrocarbon compounds to pseudo components for each carbon number from C6 to C38 for each of the three stress levels tested and analyzed in the laboratory experiments discussed herein. The normal compound and pseudo component weight percentages were obtained as described for FIGS. 7 and 11. For clarity, the normal alkane hydrocarbon and pseudo component weight percentages are taken as a percentage of the entire C3 to pseudo C38 whole oil gas chromatography areas and calculated weights as used in the pseudo compound data presented in FIG. 7. The y-axis 3060 represents the concentration in terms of weight ratio of each normal-C6/pseudo C6 to normal-C38/pseudo C38 compound found in the liquid phase. The x-axis 3061 contains the identity of each normal alkane hydrocarbon compound to pseudo component ratio from normal-C6/pseudo C6 to normal-C38/pseudo C38. The data points occurring on line 3062 represent the weight ratio of each normal-C6/pseudo C6 to normal-C38/pseudo C38 ratio for the unstressed experiment of Example 1. The data points occurring on line 3063 represent the weight ratio of each normal-C6/pseudo C6 to normal-C38/pseudo C38 ratio for the 400 psi stressed experiment of Example 3. While the data points occurring on line 3064 represent the weight ratio of each normal-C6/pseudo C6 to normal-C38/pseudo C38 ratio for the 1,000 psi stressed experiment of Example 4. From FIG. 15 it can be seen that the hydrocarbon liquid produced in the unstressed experiment, represented by data points on line 3062, contains a greater weight percentage of normal alkane hydrocarbon compounds to pseudo components in the C10 to C26 range, both as compared to the 400 psi stress experiment hydrocarbon liquid and the 1,000 psi stress experiment hydrocarbon liquid. Looking now at the data points occurring on line 3063, it is apparent that the intermediate level 400 psi stress experiment produced a hydrocarbon liquid having normal alkane hydrocarbon compound to pseudo component ratios in the C10 to C26 range between the unstressed experiment represented by line 3062 and the 1,000 psi stressed experiment represented by line 3064. Lastly, it is apparent that the high level 1,000 psi stress experiment produced a hydrocarbon liquid having normal alkane hydrocarbon compound to pseudo component ratios in the C10 to C26 range less than both the unstressed experiment represented by line 3062 and the 400 psi stressed experiment represented by line 3063. Thus pyrolyzing oil shale under increasing levels of lithostatic stress appears to produce hydrocarbon liquids having lower concentrations of normal alkane hydrocarbons as compared to the total hydrocarbons for a given carbon number occurring between C10 and C26.

From the above-described data, it can be seen that heating and pyrolysis of oil shale under increasing levels of stress results in a condensable hydrocarbon fluid product that is lighter (i.e., greater proportion of lower carbon number compounds or components relative to higher carbon number compounds or components) and contains a lower concentration of normal alkane hydrocarbon compounds. Such a product may be suitable for refining into gasoline and distillate products. Further, such a product, either before or after further fractionation, may have utility as a feed stock for certain chemical processes.

In some embodiments, the produced hydrocarbon fluid includes a condensable hydrocarbon portion. In some embodiments the condensable hydrocarbon portion may have one or more of a total C7 to total C20 weight ratio greater than 0.8, a total C8 to total C20 weight ratio greater than 1.7, a total C9 to total C20 weight ratio greater than 2.5, a total C10 to total C20 weight ratio greater than 2.8, a total C11 to total C20 weight ratio greater than 2.3, a total C12 to total C20 weight ratio greater than 2.3, a total C13 to total C20 weight ratio greater than 2.9, a total C14 to total C20 weight ratio greater than 2.2, a total C15 to total C20 weight ratio greater than 2.2, and a total C16 to total C20 weight ratio greater than 1.6. In alternative embodiments the condensable hydrocarbon portion has one or more of a total C7 to total C20 weight ratio greater than 2.5, a total C8 to total C20 weight ratio greater than 3.0, a total C9 to total C20 weight ratio greater than 3.5, a total C10 to total C20 weight ratio greater than 3.5, a total C11 to total C20 weight ratio greater than 3.0, and a total C12 to total C20 weight ratio greater than 3.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a total C7 to total C20 weight ratio greater than 3.5, a total C8 to total C20 weight ratio greater than 4.3, a total C9 to total C20 weight ratio greater than 4.5, a total C10 to total C20 weight ratio greater than 4.2, a total C11 to total C20 weight ratio greater than 3.7, and a total C12 to total C20 weight ratio greater than 3.5. As used in this paragraph and in the claims, the phrase “one or more” followed by a listing of different compound or component ratios with the last ratio introduced by the conjunction “and” is meant to include a condensable hydrocarbon portion that has at least one of the listed ratios or that has two or more, or three or more, or four or more, etc., or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also have additional ratios of different compounds or components that are not included in a particular sentence or claim and still fall within the scope of such a sentence or claim. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion has a total C7 to total C20 weight ratio greater than 0.8. Alternatively, the condensable hydrocarbon portion may have a total C7 to total C20 weight ratio greater than 1.0, greater than 1.5, greater than 2.0, greater than 2.5, greater than 3.5 or greater than 3.7. In alternative embodiments, the condensable hydrocarbon portion may have a total C7 to total C20 weight ratio less than 10.0, less than 7.0, less than 5.0 or less than 4.0. In some embodiments the condensable hydrocarbon portion has a total C8 to total C20 weight ratio greater than 1.7. Alternatively, the condensable hydrocarbon portion may have a total C8 to total C20 weight ratio greater than 2.0, greater than 2.5, greater than 3.0, greater than 4.0, greater than 4.4, or greater than 4.6. In alternative embodiments, the condensable hydrocarbon portion may have a total C8 to total C20 weight ratio less than 7.0 or less than 6.0. In some embodiments the condensable hydrocarbon portion has a total C9 to total C20 weight ratio greater than 2.5. Alternatively, the condensable hydrocarbon portion may have a total C9 to total C20 weight ratio greater than 3.0, greater than 4.0, greater than 4.5, or greater than 4.7. In alternative embodiments, the condensable hydrocarbon portion may have a total C9 to total C20 weight ratio less than 7.0 or less than 6.0. In some embodiments the condensable hydrocarbon portion has a total C10 to total C20 weight ratio greater than 2.8. Alternatively, the condensable hydrocarbon portion may have a total C10 to total C20 weight ratio greater than 3.0, greater than 3.5, greater than 4.0, or greater than 4.3. In alternative embodiments, the condensable hydrocarbon portion may have a total C10 to total C20 weight ratio less than 7.0 or less than 6.0. In some embodiments the condensable hydrocarbon portion has a total C11 to total C20 weight ratio greater than 2.3. Alternatively, the condensable hydrocarbon portion may have a total C11 to total C20 weight ratio greater than 2.5, greater than 3.5, greater than 3.7, greater than 4.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C11 to total C20 weight ratio less than 7.0 or less than 6.0. In some embodiments the condensable hydrocarbon portion has a total C12 to total C20 weight ratio greater than 2.3. Alternatively, the condensable hydrocarbon portion may have a total C12 to total C20 weight ratio greater than 2.5, greater than 3.0, greater than 3.5, or greater than 3.7. In alternative embodiments, the condensable hydrocarbon portion may have a total C12 to total C20 weight ratio less than 7.0 or less than 6.0. In some embodiments the condensable hydrocarbon portion has a total C13 to total C20 weight ratio greater than 2.9. Alternatively, the condensable hydrocarbon portion may have a total C13 to total C20 weight ratio greater than 3.0, greater than 3.1, or greater than 3.2. In alternative embodiments, the condensable hydrocarbon portion may have a total C13 to total C20 weight ratio less than 6.0 or less than 5.0. In some embodiments the condensable hydrocarbon portion has a total C14 to total C20 weight ratio greater than 2.2. Alternatively, the condensable hydrocarbon portion may have a total C14 to total C20 weight ratio greater than 2.5, greater than 2.6, or greater than 2.7. In alternative embodiments, the condensable hydrocarbon portion may have a total C14 to total C20 weight ratio less than 6.0 or less than 4.0. In some embodiments the condensable hydrocarbon portion has a total C15 to total C20 weight ratio greater than 2.2. Alternatively, the condensable hydrocarbon portion may have a total C15 to total C20 weight ratio greater than 2.3, greater than 2.4, or greater than 2.6. In alternative embodiments, the condensable hydrocarbon portion may have a total C15 to total C20 weight ratio less than 6.0 or less than 4.0. In some embodiments the condensable hydrocarbon portion has a total C16 to total C20 weight ratio greater than 1.6. Alternatively, the condensable hydrocarbon portion may have a total C16 to total C20 weight ratio greater than 1.8, greater than 2.3, or greater than 2.5. In alternative embodiments, the condensable hydrocarbon portion may have a total C16 to total C20 weight ratio less than 5.0 or less than 4.0. Certain features of the present invention are described in terms of a set of numerical upper limits (e.g. “less than”) and a set of numerical lower limits (e.g. “greater than”) in the preceding paragraph. It should be appreciated that ranges formed by any combination of these limits are within the scope of the invention unless otherwise indicated. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion may have the one or more of a total C7 to total C25 weight ratio greater than 2.0, a total C8 to total C25 weight ratio greater than 4.5, a total C9 to total C25 weight ratio greater than 6.5, a total C10 to total C25 weight ratio greater than 7.5, a total C11 to total C25 weight ratio greater than 6.5, a total C12 to total C25 weight ratio greater than 6.5, a total C13 to total C25 weight ratio greater than 8.0, a total C14 to total C25 weight ratio greater than 6.0, a total C15 to total C25 weight ratio greater than 6.0, a total C16 to total C25 weight ratio greater than 4.5, a total C17 to total C25 weight ratio greater than 4.8, and a total C18 to total C25 weight ratio greater than 4.5. In alternative embodiments the condensable hydrocarbon portion has one or more of a total C7 to total C25 weight ratio greater than 7.0, a total C8 to total C25 weight ratio greater than 10.0, a total C9 to total C25 weight ratio greater than 10.0, a total C10 to total C25 weight ratio greater than 10.0, a total C11 to total C25 weight ratio greater than 8.0, and a total C12 to total C25 weight ratio greater than 8.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a total C7 to total C25 weight ratio greater than 13.0, a total C8 to total C25 weight ratio greater than 17.0, a total C9 to total C25 weight ratio greater than 17.0, a total C10 to total C25 weight ratio greater than 15.0, a total C11 to total C25 weight ratio greater than 14.0, and a total C12 to total C25 weight ratio greater than 13.0. As used in this paragraph and in the claims, the phrase “one or more” followed by a listing of different compound or component ratios with the last ratio introduced by the conjunction “and” is meant to include a condensable hydrocarbon portion that has at least one of the listed ratios or that has two or more, or three or more, or four or more, etc., or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also have additional ratios of different compounds or components that are not included in a particular sentence or claim and still fall within the scope of such a sentence or claim. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion has a total C7 to total C25 weight ratio greater than 2.0. Alternatively, the condensable hydrocarbon portion may have a total C7 to total C25 weight ratio greater than 3.0, greater than 5.0, greater than 10.0, greater than 13.0, or greater than 15.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C7 to total C25 weight ratio less than 30.0 or less than 25.0. In some embodiments the condensable hydrocarbon portion has a total C8 to total C25 weight ratio greater than 4.5. Alternatively, the condensable hydrocarbon portion may have a total C8 to total C25 weight ratio greater than 5.0, greater than 7.0, greater than 10.0, greater than 15.0, or greater than 17.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C8 to total C25 weight ratio less than 35.0, or less than 30.0. In some embodiments the condensable hydrocarbon portion has a total C9 to total C25 weight ratio greater than 6.5. Alternatively, the condensable hydrocarbon portion may have a total C9 to total C25 weight ratio greater than 8.0, greater than 10.0, greater than 15.0, greater than 17.0, or greater than 19.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C9 to total C25 weight ratio less than 40.0 or less than 35.0. In some embodiments the condensable hydrocarbon portion has a total C10 to total C25 weight ratio greater than 7.5. Alternatively, the condensable hydrocarbon portion may have a total C10 to total C25 weight ratio greater than 10.0, greater than 14.0, or greater than 17.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C10 to total C25 weight ratio less than 35.0 or less than 30.0. In some embodiments the condensable hydrocarbon portion has a total C11 to total C25 weight ratio greater than 6.5. Alternatively, the condensable hydrocarbon portion may have a total C11 to total C25 weight ratio greater than 8.5, greater than 10.0, greater than 12.0, or greater than 14.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C11 to total C25 weight ratio less than 35.0 or less than 30.0. In some embodiments the condensable hydrocarbon portion has a total C12 to total C25 weight ratio greater than 6.5. Alternatively, the condensable hydrocarbon portion may have a total C12 to total C25 weight ratio greater than 8.5, a total C12 to total C25 weight ratio greater than 10.0, greater than 12.0, or greater than 14.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C12 to total C25 weight ratio less than 30.0 or less than 25.0. In some embodiments the condensable hydrocarbon portion has a total C13 to total C25 weight ratio greater than 8.0. Alternatively, the condensable hydrocarbon portion may have a total C13 to total C25 weight ratio greater than 10.0, greater than 12.0, or greater than 14.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C13 to total C25 weight ratio less than 25.0 or less than 20.0. In some embodiments the condensable hydrocarbon portion has a total C14 to total C25 weight ratio greater than 6.0. Alternatively, the condensable hydrocarbon portion may have a total C14 to total C25 weight ratio greater than 8.0, greater than 10.0, or greater than 12.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C14 to total C25 weight ratio less than 25.0 or less than 20.0. In some embodiments the condensable hydrocarbon portion has a total C15 to total C25 weight ratio greater than 6.0. Alternatively, the condensable hydrocarbon portion may have a total C15 to total C25 weight ratio greater than 8.0, or greater than 10.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C15 to total C25 weight ratio less than 25.0 or less than 20.0. In some embodiments the condensable hydrocarbon portion has a total C16 to total C25 weight ratio greater than 4.5. Alternatively, the condensable hydrocarbon portion may have a total C16 to total C25 weight ratio greater than 6.0, greater than 8.0, or greater than 10.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C16 to total C25 weight ratio less than 20.0 or less than 15.0. In some embodiments the condensable hydrocarbon portion has a total C17 to total C25 weight ratio greater than 4.8. Alternatively, the condensable hydrocarbon portion may have a total C17 to total C25 weight ratio greater than 5.5 or greater than 7.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C17 to total C25 weight ratio less than 20.0. In some embodiments the condensable hydrocarbon portion has a total C18 to total C25 weight ratio greater than 4.5. Alternatively, the condensable hydrocarbon portion may have a total C18 to total C25 weight ratio greater than 5.0 or greater than 5.5. In alternative embodiments, the condensable hydrocarbon portion may have a total C18 to total C25 weight ratio less than 15.0. Certain features of the present invention are described in terms of a set of numerical upper limits (e.g. “less than”) and a set of numerical lower limits (e.g. “greater than”) in the preceding paragraph. It should be appreciated that ranges formed by any combination of these limits are within the scope of the invention unless otherwise indicated. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion may have the one or more of a total C7 to total C29 weight ratio greater than 3.5, a total C8 to total C29 weight ratio greater than 9.0, a total C9 to total C29 weight ratio greater than 12.0, a total C10 to total C29 weight ratio greater than 15.0, a total C11 to total C29 weight ratio greater than 13.0, a total C12 to total C29 weight ratio greater than 12.5, and a total C13 to total C29 weight ratio greater than 16.0, a total C14 to total C29 weight ratio greater than 12.0, a total C15 to total C29 weight ratio greater than 12.0, a total C16 to total C29 weight ratio greater than 9.0, a total C17 to total C29 weight ratio greater than 10.0, a total C18 to total C29 weight ratio greater than 8.8, a total C19 to total C29 weight ratio greater than 7.0, a total C20 to total C29 weight ratio greater than 6.0, a total C21 to total C29 weight ratio greater than 5.5, and a total C22 to total C29 weight ratio greater than 4.2. In alternative embodiments the condensable hydrocarbon portion has one or more of a total C7 to total C29 weight ratio greater than 16.0, a total C8 to total C29 weight ratio greater than 19.0, a total C9 to total C29 weight ratio greater than 20.0, a total C10 to total C29 weight ratio greater than 18.0, a total C11 to total C29 weight ratio greater than 16.0, a total C12 to total C29 weight ratio greater than 15.0, and a total C13 to total C29 weight ratio greater than 17.0, a total C14 to total C29 weight ratio greater than 13.0, a total C15 to total C29 weight ratio greater than 13.0, a total C16 to total C29 weight ratio greater than 10.0, a total C17 to total C29 weight ratio greater than 11.0, a total C18 to total C29 weight ratio greater than 9.0, a total C19 to total C29 weight ratio greater than 8.0, a total C20 to total C29 weight ratio greater than 6.5, and a total C21 to total C29 weight ratio greater than 6.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a total C7 to total C29 weight ratio greater than 24.0, a total C8 to total C29 weight ratio greater than 30.0, a total C9 to total C29 weight ratio greater than 32.0, a total C10 to total C29 weight ratio greater than 30.0, a total C11 to total C29 weight ratio greater than 27.0, a total C12 to total C29 weight ratio greater than 25.0, and a total C13 to total C29 weight ratio greater than 22.0, a total C14 to total C29 weight ratio greater than 18.0, a total C15 to total C29 weight ratio greater than 18.0, a total C16 to total C29 weight ratio greater than 16.0, a total C17 to total C29 weight ratio greater than 13.0, a total C18 to total C29 weight ratio greater than 10.0, a total C19 to total C29 weight ratio greater than 9.0, and a total C20 to total C29 weight ratio greater than 7.0. As used in this paragraph and in the claims, the phrase “one or more” followed by a listing of different compound or component ratios with the last ratio introduced by the conjunction “and” is meant to include a condensable hydrocarbon portion that has at least one of the listed ratios or that has two or more, or three or more, or four or more, etc., or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also have additional ratios of different compounds or components that are not included in a particular sentence or claim and still fall within the scope of such a sentence or claim. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion has a total C7 to total C29 weight ratio greater than 3.5. Alternatively, the condensable hydrocarbon portion may have a total C7 to total C29 weight ratio greater than 5.0, greater than 10.0, greater than 18.0, greater than 20.0, or greater than 24.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C7 to total C29 weight ratio less than 60.0 or less than 50.0. In some embodiments the condensable hydrocarbon portion has a total C8 to total C29 weight ratio greater than 9.0. Alternatively, the condensable hydrocarbon portion may have a total C8 to total C29 weight ratio greater than 10.0, greater than 18.0, greater than 20.0, greater than 25.0, or greater than 30.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C8 to total C29 weight ratio less than 85.0 or less than 75.0. In some embodiments the condensable hydrocarbon portion has a total C9 to total C29 weight ratio greater than 12.0. Alternatively, the condensable hydrocarbon portion may have a total C9 to total C29 weight ratio greater than 15.0, greater than 20.0, greater than 23.0, greater than 27.0, or greater than 32.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C9 to total C29 weight ratio less than 85.0 or less than 75.0. In some embodiments the condensable hydrocarbon portion has a total C10 to total C29 weight ratio greater than 15.0. Alternatively, the condensable hydrocarbon portion may have a total C10 to total C29 weight ratio greater than 18.0, greater than 22.0, or greater than 28.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C10 to total C29 weight ratio less than 80.0 or less than 70.0. In some embodiments the condensable hydrocarbon portion has a total C11 to total C29 weight ratio greater than 13.0. Alternatively, the condensable hydrocarbon portion may have a total C11 to total C29 weight ratio greater than 16.0, greater than 18.0, greater than 24.0, or greater than 27.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C11 to total C29 weight ratio less than 75.0 or less than 65.0. In some embodiments the condensable hydrocarbon portion has a total C12 to total C29 weight ratio greater than 12.5. Alternatively, the condensable hydrocarbon portion may have a total C12 to total C29 weight ratio greater than 14.5, greater than 18.0, greater than 22.0, or greater than 25.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C12 to total C29 weight ratio less than 75.0 or less than 65.0. In some embodiments the condensable hydrocarbon portion has a total C13 to total C29 weight ratio greater than 16.0. Alternatively, the condensable hydrocarbon portion may have a total C13 to total C29 weight ratio greater than 18.0, greater than 20.0, or greater than 22.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C13 to total C29 weight ratio less than 70.0 or less than 60.0. In some embodiments the condensable hydrocarbon portion has a total C14 to total C29 weight ratio greater than 12.0. Alternatively, the condensable hydrocarbon portion may have a total C14 to total C29 weight ratio greater than 14.0, greater than 16.0, or greater than 18.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C14 to total C29 weight ratio less than 60.0 or less than 50.0. In some embodiments the condensable hydrocarbon portion has a total C15 to total C29 weight ratio greater than 12.0. Alternatively, the condensable hydrocarbon portion may have a total C15 to total C29 weight ratio greater than 15.0 or greater than 18.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C15 to total C29 weight ratio less than 60.0 or less than 50.0. In some embodiments the condensable hydrocarbon portion has a total C16 to total C29 weight ratio greater than 9.0. Alternatively, the condensable hydrocarbon portion may have a total C16 to total C29 weight ratio greater than 10.0, greater than 13.0, or greater than 16.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C16 to total C29 weight ratio less than 55.0 or less than 45.0. In some embodiments the condensable hydrocarbon portion has a total C17 to total C29 weight ratio greater than 10.0. Alternatively, the condensable hydrocarbon portion may have a total C17 to total C29 weight ratio greater than 11.0 or greater than 12.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C17 to total C29 weight ratio less than 45.0. In some embodiments the condensable hydrocarbon portion has a total C18 to total C29 weight ratio greater than 8.8. Alternatively, the condensable hydrocarbon portion may have a total C18 to total C29 weight ratio greater than 9.0 or greater than 10.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C18 to total C29 weight ratio less than 35.0. In some embodiments the condensable hydrocarbon portion has a total C19 to total C29 weight ratio greater than 7.0. Alternatively, the condensable hydrocarbon portion may have a total C19 to total C29 weight ratio greater than 8.0 or greater than 9.0. In alternative embodiments, the condensable hydrocarbon portion may have a total C19 to total C29 weight ratio less than 30.0. Certain features of the present invention are described in terms of a set of numerical upper limits (e.g. “less than”) and a set of numerical lower limits (e.g. “greater than”) in the preceding paragraph. It should be appreciated that ranges formed by any combination of these limits are within the scope of the invention unless otherwise indicated. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion may have the one or more of a total C9 to total C20 weight ratio between 2.5 and 6.0, a total C10 to total C20 weight ratio between 2.8 and 7.3, a total C11 to total C20 weight ratio between 2.6 and 6.5, a total C12 to total C20 weight ratio between 2.6 and 6.4 and a total C13 to total C20 weight ratio between 3.2 and 8.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a total C9 to total C20 weight ratio between 3.0 and 5.5, a total C10 to total C20 weight ratio between 3.2 and 7.0, a total C11 to total C20 weight ratio between 3.0 and 6.0, a total C12 to total C20 weight ratio between 3.0 and 6.0, and a total C13 to total C20 weight ratio between 3.3 and 7.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a total C9 to total C20 weight ratio between 4.6 and 5.5, a total C10 to total C20 weight ratio between 4.2 and 7.0, a total C11 to total C20 weight ratio between 3.7 and 6.0, a total C12 to total C20 weight ratio between 3.6 and 6.0, and a total C13 to total C20 weight ratio between 3.4 and 7.0. As used in this paragraph and in the claims, the phrase “one or more” followed by a listing of different compound or component ratios with the last ratio introduced by the conjunction “and” is meant to include a condensable hydrocarbon portion that has at least one of the listed ratios or that has two or more, or three or more, or four or more, etc., or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also have additional ratios of different compounds or components that are not included in a particular sentence or claim and still fall within the scope of such a sentence or claim. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion has a total C9 to total C20 weight ratio between 2.5 and 6.0. Alternatively, the condensable hydrocarbon portion may have a total C9 to total C20 weight ratio between 3.0 and 5.8, between 3.5 and 5.8, between 4.0 and 5.8, between 4.5 and 5.8, between 4.6 and 5.8, or between 4.7 and 5.8. In some embodiments the condensable hydrocarbon portion has a total C10 to total C20 weight ratio between 2.8 and 7.3. Alternatively, the condensable hydrocarbon portion may have a total C10 to total C20 weight ratio between 3.0 and 7.2, between 3.5 and 7.0, between 4.0 and 7.0, between 4.2 and 7.0, between 4.3 and 7.0, or between 4.4 and 7.0. In some embodiments the condensable hydrocarbon portion has a total C11 to total C20 weight ratio between 2.6 and 6.5. Alternatively, the condensable hydrocarbon portion may have a total C11 to total C20 weight ratio between 2.8 and 6.3, between 3.5 and 6.3, between 3.7 and 6.3, between 3.8 and 6.3, between 3.9 and 6.2, or between 4.0 and 6.2. In some embodiments the condensable hydrocarbon portion has a total C12 to total C20 weight ratio between 2.6 and 6.4. Alternatively, the condensable hydrocarbon portion may have a total C12 to total C20 weight ratio between 2.8 and 6.2, between 3.2 and 6.2, between 3.5 and 6.2, between 3.6 and 6.2, between 3.7 and 6.0, or between 3.8 and 6.0. In some embodiments the condensable hydrocarbon portion has a total C13 to total C20 weight ratio between 3.2 and 8.0. Alternatively, the condensable hydrocarbon portion may have a total C13 to total C20 weight ratio between 3.3 and 7.8, between 3.3 and 7.0, between 3.4 and 7.0, between 3.5 and 6.5, or between 3.6 and 6.0. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion may have one or more of a total C10 to total C25 weight ratio between 7.1 and 24.5, a total C11 to total C25 weight ratio between 6.5 and 22.0, a total C12 to total C25 weight ratio between 6.5 and 22.0, and a total C13 to total C25 weight ratio between 8.0 and 27.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a total C10 to total C25 weight ratio between 10.0 and 24.0, a total C11 to total C25 weight ratio between 10.0 and 21.5, a total C12 to total C25 weight ratio between 10.0 and 21.5, and a total C13 to total C25 weight ratio between 9.0 and 25.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a total C10 to total C25 weight ratio between 14.0 and 24.0, a total C11 to total C25 weight ratio between 12.5 and 21.5, a total C12 to total C25 weight ratio between 12.0 and 21.5, and a total C13 to total C25 weight ratio between 10.5 and 25.0. As used in this paragraph and in the claims, the phrase “one or more” followed by a listing of different compound or component ratios with the last ratio introduced by the conjunction “and” is meant to include a condensable hydrocarbon portion that has at least one of the listed ratios or that has two or more, or three or more, or four or more, etc., or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also have additional ratios of different compounds or components that are not included in a particular sentence or claim and still fall within the scope of such a sentence or claim. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion has a total C10 to total C25 weight ratio between 7.1 and 24.5. Alternatively, the condensable hydrocarbon portion may have a total C10 to total C25 weight ratio between 7.5 and 24.5, between 12.0 and 24.5, between 13.8 and 24.5, between 14.0 and 24.5, or between 15.0 and 24.5. In some embodiments the condensable hydrocarbon portion has a total C11 to total C25 weight ratio between 6.5 and 22.0. Alternatively, the condensable hydrocarbon portion may have a total C11 to total C25 weight ratio between 7.0 and 21.5, between 10.0 and 21.5, between 12.5 and 21.5, between 13.0 and 21.5, between 13.7 and 21.5, or between 14.5 and 21.5. In some embodiments the condensable hydrocarbon portion has a total C12 to total C25 weight ratio between 10.0 and 21.5. Alternatively, the condensable hydrocarbon portion may have a total C12 to total C25 weight ratio between 10.5 and 21.0, between 11.0 and 21.0, between 12.0 and 21.0, between 12.5 and 21.0, between 13.0 and 21.0, or between 13.5 and 21.0. In some embodiments the condensable hydrocarbon portion has a total C13 to total C25 weight ratio between 8.0 and 27.0. Alternatively, the condensable hydrocarbon portion may have a total C13 to total C25 weight ratio between 9.0 and 26.0, between 10.0 and 25.0, between 10.5 and 25.0, between 11.0 and 25.0, or between 11.5 and 25.0. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion may have one or more of a total C10 to total C29 weight ratio between 15.0 and 60.0, a total C11 to total C29 weight ratio between 13.0 and 54.0, a total C12 to total C29 weight ratio between 12.5 and 53.0, and a total C13 to total C29 weight ratio between 16.0 and 65.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a total C10 to total C29 weight ratio between 17.0 and 58.0, a total C11 to total C29 weight ratio between 15.0 and 52.0, a total C12 to total C29 weight ratio between 14.0 and 50.0, and a total C13 to total C29 weight ratio between 17.0 and 60.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a total C10 to total C29 weight ratio between 20.0 and 58.0, a total C11 to total C29 weight ratio between 18.0 and 52.0, a total C12 to total C29 weight ratio between 18.0 and 50.0, and a total C13 to total C29 weight ratio between 18.0 and 50.0. As used in this paragraph and in the claims, the phrase “one or more” followed by a listing of different compound or component ratios with the last ratio introduced by the conjunction “and” is meant to include a condensable hydrocarbon portion that has at least one of the listed ratios or that has two or more, or three or more, or four or more, etc., or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also have additional ratios of different compounds or components that are not included in a particular sentence or claim and still fall within the scope of such a sentence or claim. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion has a total C10 to total C29 weight ratio between 15.0 and 60.0. Alternatively, the condensable hydrocarbon portion may have a total C10 to total C29 weight ratio between 18.0 and 58.0, between 20.0 and 58.0, between 24.0 and 58.0, between 27.0 and 58.0, or between 30.0 and 58.0. In some embodiments the condensable hydrocarbon portion has a total C11 to total C29 weight ratio between 13.0 and 54.0. Alternatively, the condensable hydrocarbon portion may have a total C11 to total C29 weight ratio between 15.0 and 53.0, between 18.0 and 53.0, between 20.0 and 53.0, between 22.0 and 53.0, between 25.0 and 53.0, or between 27.0 and 53.0. In some embodiments the condensable hydrocarbon portion has a total C12 to total C29 weight ratio between 12.5 and 53.0. Alternatively, the condensable hydrocarbon portion may have a total C12 to total C29 weight ratio between 14.5 and 51.0, between 16.0 and 51.0, between 18.0 and 51.0, between 20.0 and 51.0, between 23.0 and 51.0, or between 25.0 and 51.0. In some embodiments the condensable hydrocarbon portion has a total C13 to total C29 weight ratio between 16.0 and 65.0. Alternatively, the condensable hydrocarbon portion may have a total C13 to total C29 weight ratio between 17.0 and 60.0, between 18.0 and 60.0, between 20.0 and 60.0, between 22.0 and 60.0, or between 25.0 and 60.0. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion may have one or more of a normal-C7 to normal-C20 weight ratio greater than 0.9, a normal-C8 to normal-C20 weight ratio greater than 2.0, a normal-C9 to normal-C20 weight ratio greater than 1.9, a normal-C10 to normal-C20 weight ratio greater than 2.2, a normal-C11 to normal-C20 weight ratio greater than 1.9, a normal-C12 to normal-C20 weight ratio greater than 1.9, a normal-C13 to normal-C20 weight ratio greater than 2.3, a normal-C14 to normal-C20 weight ratio greater than 1.8, a normal-C15 to normal-C20 weight ratio greater than 1.8, and normal-C16 to normal-C20 weight ratio greater than 1.3. In alternative embodiments the condensable hydrocarbon portion has one or more of a normal-C7 to normal-C20 weight ratio greater than 4.4, a normal-C8 to normal-C20 weight ratio greater than 3.7, a normal-C9 to normal-C20 weight ratio greater than 3.5, a normal-C10 to normal-C20 weight ratio greater than 3.4, a normal-C11 to normal-C20 weight ratio greater than 3.0, and a normal-C12 to normal-C20 weight ratio greater than 2.7. In alternative embodiments the condensable hydrocarbon portion has one or more of a normal-C7 to normal-C20 weight ratio greater than 4.9, a normal-C8 to normal-C20 weight ratio greater than 4.5, a normal-C9 to normal-C20 weight ratio greater than 4.4, a normal-C10 to normal-C20 weight ratio greater than 4.1, a normal-C11 to normal-C20 weight ratio greater than 3.7, and a normal-C12 to normal-C20 weight ratio greater than 3.0. As used in this paragraph and in the claims, the phrase “one or more” followed by a listing of different compound or component ratios with the last ratio introduced by the conjunction “and” is meant to include a condensable hydrocarbon portion that has at least one of the listed ratios or that has two or more, or three or more, or four or more, etc., or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also have additional ratios of different compounds or components that are not included in a particular sentence or claim and still fall within the scope of such a sentence or claim. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion has a normal-C7 to normal-C20 weight ratio greater than 0.9. Alternatively, the condensable hydrocarbon portion may have a normal-C7 to normal-C20 weight ratio greater than 1.0, than 2.0, greater than 3.0, greater than 4.0, greater than 4.5, or greater than 5.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C7 to normal-C20 weight ratio less than 8.0 or less than 7.0. In some embodiments the condensable hydrocarbon portion has a normal-C8 to normal-C20 weight ratio greater than 1.7. Alternatively, the condensable hydrocarbon portion may have a normal-C8 to normal-C20 weight ratio greater than 2.0, greater than 2.5, greater than 3.0, greater than 3.5, greater than 4.0, or greater than 4.4. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C8 to normal-C20 weight ratio less than 8.0 or less than 7.0. In some embodiments the condensable hydrocarbon portion has a normal-C9 to normal-C20 weight ratio greater than 1.9. Alternatively, the condensable hydrocarbon portion may have a normal-C9 to normal-C20 weight ratio greater than 2.0, greater than 3.0, greater than 4.0, or greater than 4.5. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C9 to normal-C20 weight ratio less than 7.0 or less than 6.0. In some embodiments the condensable hydrocarbon portion has a normal-C10 to normal-C20 weight ratio greater than 2.2. Alternatively, the condensable hydrocarbon portion may have a normal-C10 to normal-C20 weight ratio greater than 2.8, greater than 3.3, greater than 3.5, or greater than 4.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C10 to normal-C20 weight ratio less than 7.0 or less than 6.0. In some embodiments the condensable hydrocarbon portion has a normal-C11 to normal-C20 weight ratio greater than 1.9. Alternatively, the condensable hydrocarbon portion may have a normal-C11 to normal-C20 weight ratio greater than 2.5, greater than 3.0, greater than 3.5, or greater than 3.7. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C11 to normal-C20 weight ratio less than 7.0 or less than 6.0. In some embodiments the condensable hydrocarbon portion has a normal-C12 to normal-C20 weight ratio greater than 1.9. Alternatively, the condensable hydrocarbon portion may have a normal-C12 to normal-C20 weight ratio greater than 2.0, greater than 2.2, greater than 2.6, or greater than 3.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C12 to normal-C20 weight ratio less than 7.0 or less than 6.0. In some embodiments the condensable hydrocarbon portion has a normal-C13 to normal-C20 weight ratio greater than 2.3. Alternatively, the condensable hydrocarbon portion may have a normal-C13 to normal-C20 weight ratio greater than 2.5, greater than 2.7, or greater than 3.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C13 to normal-C20 weight ratio less than 6.0 or less than 5.0. In some embodiments the condensable hydrocarbon portion has a normal-C14 to normal-C20 weight ratio greater than 1.8. Alternatively, the condensable hydrocarbon portion may have a normal-C14 to normal-C20 weight ratio greater than 2.0, greater than 2.2, or greater than 2.5. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C14 to normal-C20 weight ratio less than 6.0 or less than 4.0. In some embodiments the condensable hydrocarbon portion has a normal-C15 to normal-C20 weight ratio greater than 1.8. Alternatively, the condensable hydrocarbon portion may have a normal-C15 to normal-C20 weight ratio greater than 2.0, greater than 2.2, or greater than 2.4. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C15 to normal-C20 weight ratio less than 6.0 or less than 4.0. In some embodiments the condensable hydrocarbon portion has a normal-C16 to normal-C20 weight ratio greater than 1.3. Alternatively, the condensable hydrocarbon portion may have a normal-C16 to normal-C20 weight ratio greater than 1.5, greater than 1.7, or greater than 2.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C16 to normal-C20 weight ratio less than 5.0 or less than 4.0. Certain features of the present invention are described in terms of a set of numerical upper limits (e.g. “less than”) and a set of numerical lower limits (e.g. “greater than”) in the preceding paragraph. It should be appreciated that ranges formed by any combination of these limits are within the scope of the invention unless otherwise indicated. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion may have one or more of a normal-C7 to normal-C25 weight ratio greater than 1.9, a normal-C8 to normal-C25 weight ratio greater than 3.9, a normal-C9 to normal-C25 weight ratio greater than 3.7, a normal-C10 to normal-C25 weight ratio greater than 4.4, a normal-C11 to normal-C25 weight ratio greater than 3.8, a normal-C12 to normal-C25 weight ratio greater than 3.7, a normal-C13 to normal-C25 weight ratio greater than 4.7, a normal-C14 to normal-C25 weight ratio greater than 3.7, a normal-C15 to normal-C25 weight ratio greater than 3.7, a normal-C16 to normal-C25 weight ratio greater than 2.5, a normal-C17 to normal-C25 weight ratio greater than 3.0, and a normal-C18 to normal-C25 weight ratio greater than 3.4. In alternative embodiments the condensable hydrocarbon portion has one or more of a normal-C7 to normal-C25 weight ratio greater than 10, a normal-C8 to normal-C25 weight ratio greater than 8.0, a normal-C9 to normal-C25 weight ratio greater than 7.0, a normal-C10 to normal-C25 weight ratio greater than 7.0, a normal-C11 to normal-C25 weight ratio greater than 7.0, and a normal-C12 to normal-C25 weight ratio greater than 6.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a normal-C7 to normal-C25 weight ratio greater than 10.0, a normal-C8 to normal-C25 weight ratio greater than 12.0, a normal-C9 to normal-C25 weight ratio greater than 11.0, a normal-C10 to normal-C25 weight ratio greater than 11.0, a normal-C11 to normal-C25 weight ratio greater than 9.0, and a normal-C12 to normal-C25 weight ratio greater than 8.0. As used in this paragraph and in the claims, the phrase “one or more” followed by a listing of different compound or component ratios with the last ratio introduced by the conjunction “and” is meant to include a condensable hydrocarbon portion that has at least one of the listed ratios or that has two or more, or three or more, or four or more, etc., or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also have additional ratios of different compounds or components that are not included in a particular sentence or claim and still fall within the scope of such a sentence or claim. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion has a normal-C7 to normal-C25 weight ratio greater than 1.9. Alternatively, the condensable hydrocarbon portion may have a normal-C7 to normal-C25 weight ratio greater than 3.0, greater than 5.0, greater than 8.0, greater than 10.0, or greater than 13.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C7 to normal-C25 weight ratio less than 35.0 or less than 25.0. In some embodiments the condensable hydrocarbon portion has a normal-C8 to normal-C25 weight ratio greater than 3.9. Alternatively, the condensable hydrocarbon portion may have a normal-C8 to normal-C25 weight ratio greater than 4.5, greater than 6.0, greater than 8.0, greater than 10.0, or greater than 13.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C8 to normal-C25 weight ratio less than 35.0 or less than 25.0. In some embodiments the condensable hydrocarbon portion has a normal-C9 to normal-C25 weight ratio greater than 3.7. Alternatively, the condensable hydrocarbon portion may have a normal-C9 to normal-C25 weight ratio greater than 4.5, greater than 7.0, greater than 10.0, greater than 12.0, or greater than 13.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C9 to normal-C25 weight ratio less than 35.0 or less than 25.0. In some embodiments the condensable hydrocarbon portion has a normal-C10 to normal-C25 weight ratio greater than 4.4. Alternatively, the condensable hydrocarbon portion may have a normal-C10 to normal-C25 weight ratio greater than 6.0, greater than 8.0, or greater than 11.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C10 to normal-C25 weight ratio less than 35.0 or less than 25.0. In some embodiments the condensable hydrocarbon portion has a normal-C11 to normal-C25 weight ratio greater than 3.8. Alternatively, the condensable hydrocarbon portion may have a normal-C11 to normal-C25 weight ratio greater than 4.5, greater than 7.0, greater than 8.0, or greater than 10.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C11 to normal-C25 weight ratio less than 35.0 or less than 25.0. In some embodiments the condensable hydrocarbon portion has a normal-C12 to normal-C25 weight ratio greater than 3.7. Alternatively, the condensable hydrocarbon portion may have a normal-C12 to normal-C25 weight ratio greater than 4.5, greater than 6.0, greater than 7.0, or greater than 8.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C12 to normal-C25 weight ratio less than 30.0 or less than 20.0. In some embodiments the condensable hydrocarbon portion has a normal-C13 to normal-C25 weight ratio greater than 4.7. Alternatively, the condensable hydrocarbon portion may have a normal-C13 to normal-C25 weight ratio greater than 5.0, greater than 6.0, or greater than 7.5. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C13 to normal-C25 weight ratio less than 25.0 or less than 20.0. In some embodiments the condensable hydrocarbon portion has a normal-C14 to normal-C25 weight ratio greater than 3.7. Alternatively, the condensable hydrocarbon portion may have a normal-C14 to normal-C25 weight ratio greater than 4.5, greater than 5.5, or greater than 7.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C14 to normal-C25 weight ratio less than 25.0 or less than 20.0. In some embodiments the condensable hydrocarbon portion has a normal-C15 to normal-C25 weight ratio greater than 3.7. Alternatively, the condensable hydrocarbon portion may have a normal-C15 to normal-C25 weight ratio greater than 4.2 or greater than 5.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C15 to normal-C25 weight ratio less than 25.0 or less than 20.0. In some embodiments the condensable hydrocarbon portion has a normal-C16 to normal-C25 weight ratio greater than 2.5. Alternatively, the condensable hydrocarbon portion may have a normal-C16 to normal-C25 weight ratio greater than 3.0, greater than 4.0, or greater than 5.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C16 to normal-C25 weight ratio less than 20.0 or less than 15.0. In some embodiments the condensable hydrocarbon portion has a normal-C17 to normal-C25 weight ratio greater than 3.0. Alternatively, the condensable hydrocarbon portion may have a normal-C17 to normal-C25 weight ratio greater than 3.5 or greater than 4.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C17 to normal-C25 weight ratio less than 20.0. In some embodiments the condensable hydrocarbon portion has a normal-C18 to normal-C25 weight ratio greater than 3.4. Alternatively, the condensable hydrocarbon portion may have a normal-C18 to normal-C25 weight ratio greater than 3.6 or greater than 4.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C18 to normal-C25 weight ratio less than 15.0. Certain features of the present invention are described in terms of a set of numerical upper limits (e.g. “less than”) and a set of numerical lower limits (e.g. “greater than”) in the preceding paragraph. It should be appreciated that ranges formed by any combination of these limits are within the scope of the invention unless otherwise indicated. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion may have one or more of a normal-C7 to normal-C29 weight ratio greater than 18.0, a normal-C8 to normal-C29 weight ratio greater than 16.0, a normal-C9 to normal-C29 weight ratio greater than 14.0, a normal-C10 to normal-C29 weight ratio greater than 14.0, a normal-C11 to normal-C29 weight ratio greater than 13.0, a normal-C12 to normal-C29 weight ratio greater than 11.0, a normal-C13 to normal-C29 weight ratio greater than 10.0, a normal-C14 to normal-C29 weight ratio greater than 9.0, a normal-C15 to normal-C29 weight ratio greater than 8.0, a normal-C16 to normal-C29 weight ratio greater than 8.0, a normal-C17 to normal-C29 weight ratio greater than 6.0, a normal-C18 to normal-C29 weight ratio greater than 6.0, a normal-C19 to normal-C29 weight ratio greater than 5.0, a normal-C20 to normal-C29 weight ratio greater than 4.0, a normal-C21 to normal-C29 weight ratio greater than 3.6, and a normal-C22 to normal-C29 weight ratio greater than 2.8. In alternative embodiments the condensable hydrocarbon portion has one or more of a normal-C7 to normal-C29 weight ratio greater than 20.0, a normal-C8 to normal-C29 weight ratio greater than 18.0, a normal-C9 to normal-C29 weight ratio greater than 17.0, a normal-C10 to normal-C29 weight ratio greater than 16.0, a normal-C11 to normal-C29 weight ratio greater than 15.0, a normal-C12 to normal-C29 weight ratio greater than 12.5, a normal-C13 to normal-C29 weight ratio greater than 11.0, a normal-C14 to normal-C29 weight ratio greater than 10.0, a normal-C15 to normal-C29 weight ratio greater than 8.0, a normal-C16 to normal-C29 weight ratio greater than 8.0, a normal-C17 to normal-C29 weight ratio greater than 7.0, a normal-C18 to normal-C29 weight ratio greater than 6.5, a normal-C19 to normal-C29 weight ratio greater than 5.5, a normal-C20 to normal-C29 weight ratio greater than 4.5, and a normal-C21 to normal-C29 weight ratio greater than 4.0. In alternative embodiments the condensable hydrocarbon portion has one or more of a normal-C7 to normal-C29 weight ratio greater than 23.0, a normal-C8 to normal-C29 weight ratio greater than 21.0, a normal-C9 to normal-C29 weight ratio greater than 20.0, a normal-C10 to normal-C29 weight ratio greater than 19.0, a normal-C11 to normal-C29 weight ratio greater than 17.0, a normal-C12 to normal-C29 weight ratio greater than 14.0, a normal-C13 to normal-C29 weight ratio greater than 12.0, a normal-C14 to normal-C29 weight ratio greater than 11.0, a normal-C15 to normal-C29 weight ratio greater than 9.0, a normal-C16 to normal-C29 weight ratio greater than 9.0, a normal-C17 to normal-C29 weight ratio greater than 7.5, a normal-C18 to normal-C29 weight ratio greater than 7.0, a normal-C19 to normal-C29 weight ratio greater than 6.5, a normal-C20 to normal-C29 weight ratio greater than 4.8, and a normal-C21 to normal-C29 weight ratio greater than 4.5. As used in this paragraph and in the claims, the phrase “one or more” followed by a listing of different compound or component ratios with the last ratio introduced by the conjunction “and” is meant to include a condensable hydrocarbon portion that has at least one of the listed ratios or that has two or more, or three or more, or four or more, etc., or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also have additional ratios of different compounds or components that are not included in a particular sentence or claim and still fall within the scope of such a sentence or claim. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion has a normal-C7 to normal-C29 weight ratio greater than 18.0. Alternatively, the condensable hydrocarbon portion may have a normal-C7 to normal-C29 weight ratio greater than 20.0, greater than 22.0, greater than 25.0, greater than 30.0, or greater than 35.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C7 to normal-C29 weight ratio less than 70.0 or less than 60.0. In some embodiments the condensable hydrocarbon portion has a normal-C8 to normal-C29 weight ratio greater than 16.0. Alternatively, the condensable hydrocarbon portion may have a normal-C8 to normal-C29 weight ratio greater than 18.0, greater than 22.0, greater than 25.0, greater than 27.0, or greater than 30.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C8 to normal-C29 weight ratio less than 85.0 or less than 75.0. In some embodiments the condensable hydrocarbon portion has a normal-C9 to normal-C29 weight ratio greater than 14.0. Alternatively, the condensable hydrocarbon portion may have a normal-C9 to normal-C29 weight ratio greater than 18.0, greater than 20.0, greater than 23.0, greater than 27.0, or greater than 30.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C9 to normal-C29 weight ratio less than 85.0 or less than 75.0. In some embodiments the condensable hydrocarbon portion has a normal-C10 to normal-C29 weight ratio greater than 14.0. Alternatively, the condensable hydrocarbon portion may have a normal-C10 to normal-C29 weight ratio greater than 20.0, greater than 25.0, or greater than 30.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C10 to normal-C29 weight ratio less than 80.0 or less than 70.0. In some embodiments the condensable hydrocarbon portion has a normal-C11 to normal-C29 weight ratio greater than 13.0. Alternatively, the condensable hydrocarbon portion may have a normal-C11 to normal-C29 weight ratio greater than 16.0, greater than 18.0, greater than 24.0, or greater than 27.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C11 to normal-C29 weight ratio less than 75.0 or less than 65.0. In some embodiments the condensable hydrocarbon portion has a normal-C12 to normal-C29 weight ratio greater than 11.0. Alternatively, the condensable hydrocarbon portion may have a normal-C12 to normal-C29 weight ratio greater than 14.5, greater than 18.0, greater than 22.0, or greater than 25.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C12 to normal-C29 weight ratio less than 75.0 or less than 65.0. In some embodiments the condensable hydrocarbon portion has a normal-C13 to normal-C29 weight ratio greater than 10.0. Alternatively, the condensable hydrocarbon portion may have a normal-C13 to normal-C29 weight ratio greater than 18.0, greater than 20.0, or greater than 22.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C13 to normal-C29 weight ratio less than 70.0 or less than 60.0. In some embodiments the condensable hydrocarbon portion has a normal-C14 to normal-C29 weight ratio greater than 9.0. Alternatively, the condensable hydrocarbon portion may have a normal-C14 to normal-C29 weight ratio greater than 14.0, greater than 16.0, or greater than 18.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C14 to normal-C29 weight ratio less than 60.0 or less than 50.0. In some embodiments the condensable hydrocarbon portion has a normal-C15 to normal-C29 weight ratio greater than 8.0. Alternatively, the condensable hydrocarbon portion may have a normal-C15 to normal-C29 weight ratio greater than 12.0 or greater than 16.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C15 to normal-C29 weight ratio less than 60.0 or less than 50.0. In some embodiments the condensable hydrocarbon portion has a normal-C16 to normal-C29 weight ratio greater than 8.0. Alternatively, the condensable hydrocarbon portion may have a normal-C16 to normal-C29 weight ratio greater than 10.0, greater than 13.0, or greater than 15.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C16 to normal-C29 weight ratio less than 55.0 or less than 45.0. In some embodiments the condensable hydrocarbon portion has a normal-C17 to normal-C29 weight ratio greater than 6.0. Alternatively, the condensable hydrocarbon portion may have a normal-C17 to normal-C29 weight ratio greater than 8.0 or greater than 12.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C17 to normal-C29 weight ratio less than 45.0. In some embodiments the condensable hydrocarbon portion has a normal-C18 to normal-C29 weight ratio greater than 6.0. Alternatively, the condensable hydrocarbon portion may have a normal-C18 to normal-C29 weight ratio greater than 8.0 or greater than 10.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C18 to normal-C29 weight ratio less than 35.0. In some embodiments the condensable hydrocarbon portion has a normal-C19 to normal-C29 weight ratio greater than 5.0. Alternatively, the condensable hydrocarbon portion may have a normal-C19 to normal-C29 weight ratio greater than 7.0 or greater than 9.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C19 to normal-C29 weight ratio less than 30.0. In some embodiments the condensable hydrocarbon portion has a normal-C20 to normal-C29 weight ratio greater than 4.0. Alternatively, the condensable hydrocarbon portion may have a normal-C20 to normal-C29 weight ratio greater than 6.0 or greater than 8.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C20 to normal-C29 weight ratio less than 30.0. In some embodiments the condensable hydrocarbon portion has a normal-C21 to normal-C29 weight ratio greater than 3.6. Alternatively, the condensable hydrocarbon portion may have a normal-C21 to normal-C29 weight ratio greater than 4.0 or greater than 6.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C21 to normal-C29 weight ratio less than 30.0. In some embodiments the condensable hydrocarbon portion has a normal-C22 to normal-C29 weight ratio greater than 2.8. Alternatively, the condensable hydrocarbon portion may have a normal-C22 to normal-C29 weight ratio greater than 3.0. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C22 to normal-C29 weight ratio less than 30.0. Certain features of the present invention are described in terms of a set of numerical upper limits (e.g. “less than”) and a set of numerical lower limits (e.g. “greater than”) in the preceding paragraph. It should be appreciated that ranges formed by any combination of these limits are within the scope of the invention unless otherwise indicated. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion may have one or more of a normal-C10 to total C10 weight ratio less than 0.31, a normal-C11 to total C11 weight ratio less than 0.32, a normal-C12 to total C12 weight ratio less than 0.29, a normal-C13 to total C13 weight ratio less than 0.28, a normal-C14 to total C14 weight ratio less than 0.31, a normal-C15 to total C15 weight ratio less than 0.27, a normal-C16 to total C16 weight ratio less than 0.31, a normal-C17 to total C17 weight ratio less than 0.31, a normal-C18 to total C18 weight ratio less than 0.37, normal-C19 to total C19 weight ratio less than 0.37, a normal-C20 to total C20 weight ratio less than 0.37, a normal-C21 to total C21 weight ratio less than 0.37, a normal-C22 to total C22 weight ratio less than 0.38, normal-C23 to total C23 weight ratio less than 0.43, a normal-C24 to total C24 weight ratio less than 0.48, and a normal-C25 to total C25 weight ratio less than 0.53. In alternative embodiments the condensable hydrocarbon portion has one or more of a normal-C11 to total C11 weight ratio less than 0.30, a normal-C12 to total C12 weight ratio less than 0.27, a normal-C13 to total C13 weight ratio less than 0.26, a normal-C14 to total C14 weight ratio less than 0.29, a normal-C15 to total C15 weight ratio less than 0.24, a normal-C16 to total C16 weight ratio less than 0.25, a normal-C17 to total C17 weight ratio less than 0.29, a normal-C18 to total C18 weight ratio less than 0.31, normal-C19 to total C19 weight ratio less than 0.35, a normal-C20 to total C20 weight ratio less than 0.33, a normal-C21 to total C21 weight ratio less than 0.33, a normal-C22 to total C22 weight ratio less than 0.35, normal-C23 to total C23 weight ratio less than 0.40, a normal-C24 to total C24 weight ratio less than 0.45, and a normal-C25 to total C25 weight ratio less than 0.49. In alternative embodiments the condensable hydrocarbon portion has one or more of a normal-C11 to total C11 weight ratio less than 0.28, a normal-C12 to total C12 weight ratio less than 0.25, a normal-C13 to total C13 weight ratio less than 0.24, a normal-C14 to total C14 weight ratio less than 0.27, a normal-C15 to total C15 weight ratio less than 0.22, a normal-C16 to total C16 weight ratio less than 0.23, a normal-C17 to total C17 weight ratio less than 0.25, a normal-C18 to total C18 weight ratio less than 0.28, normal-C19 to total C19 weight ratio less than 0.31, a normal-C20 to total C20 weight ratio less than 0.29, a normal-C21 to total C21 weight ratio less than 0.30, a normal-C22 to total C22 weight ratio less than 0.28, normal-C23 to total C23 weight ratio less than 0.33, a normal-C24 to total C24 weight ratio less than 0.40, and a normal-C25 to total C25 weight ratio less than 0.45. As used in this paragraph and in the claims, the phrase “one or more” followed by a listing of different compound or component ratios with the last ratio introduced by the conjunction “and” is meant to include a condensable hydrocarbon portion that has at least one of the listed ratios or that has two or more, or three or more, or four or more, etc., or all of the listed ratios. Further, a particular condensable hydrocarbon portion may also have additional ratios of different compounds or components that are not included in a particular sentence or claim and still fall within the scope of such a sentence or claim. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

In some embodiments the condensable hydrocarbon portion has a normal-C10 to total C10 weight ratio less than 0.31. Alternatively, the condensable hydrocarbon portion may have a normal-C10 to total C10 weight ratio less than 0.30 or less than 0.29. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C10 to total C10 weight ratio greater than 0.15 or greater than 0.20. In some embodiments the condensable hydrocarbon portion has a normal-C11 to total C11 weight ratio less than 0.32. Alternatively, the condensable hydrocarbon portion may have a normal-C11 to total C11 weight ratio less than 0.31, less than 0.30, or less than 0.29. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C11 to total C11 weight ratio greater than 0.15 or greater than 0.20. In some embodiments the condensable hydrocarbon portion has a normal-C12 to total C12 weight ratio less than 0.29. Alternatively, the condensable hydrocarbon portion may have a normal-C12 to total C12 weight ratio less than 0.26, or less than 0.24. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C12 to total C12 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a normal-C13 to total C13 weight ratio less than 0.28. Alternatively, the condensable hydrocarbon portion may have a normal-C13 to total C13 weight ratio less than 0.27, less than 0.25, or less than 0.23. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C13 to total C13 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a normal-C14 to total C14 weight ratio less than 0.31. Alternatively, the condensable hydrocarbon portion may have a normal-C14 to total C14 weight ratio less than 0.30, less than 0.28, or less than 0.26. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C14 to total C14 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a normal-C15 to total C15 weight ratio less than 0.27. Alternatively, the condensable hydrocarbon portion may have a normal-C15 to total C15 weight ratio less than 0.26, less than 0.24, or less than 0.22. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C15 to total C15 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a normal-C16 to total C16 weight ratio less than 0.31. Alternatively, the condensable hydrocarbon portion may have a normal-C16 to total C16 weight ratio less than 0.29, less than 0.26, or less than 0.24. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C16 to total C16 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a normal-C17 to total C17 weight ratio less than 0.31. Alternatively, the condensable hydrocarbon portion may have a normal-C17 to total C17 weight ratio less than 0.29, less than 0.27, or less than 0.25. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C17 to total C17 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a normal-C18 to total C18 weight ratio less than 0.37. Alternatively, the condensable hydrocarbon portion may have a normal-C18 to total C18 weight ratio less than 0.35, less than 0.31, or less than 0.28. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C18 to total C18 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a normal-C19 to total C19 weight ratio less than 0.37. Alternatively, the condensable hydrocarbon portion may have a normal-C19 to total C19 weight ratio less than 0.36, less than 0.34, or less than 0.31. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C19 to total C19 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a normal-C20 to total C20 weight ratio less than 0.37. Alternatively, the condensable hydrocarbon portion may have a normal-C20 to total C20 weight ratio less than 0.35, less than 0.32, or less than 0.29. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C20 to total C20 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a normal-C21 to total C21 weight ratio less than 0.37. Alternatively, the condensable hydrocarbon portion may have a normal-C21 to total C21 weight ratio less than 0.35, less than 0.32, or less than 0.30. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C21 to total C21 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a normal-C22 to total C22 weight ratio less than 0.38. Alternatively, the condensable hydrocarbon portion may have a normal-C22 to total C22 weight ratio less than 0.36, less than 0.34, or less than 0.30. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C22 to total C22 weight ratio greater than 0.10 or greater than 0.15. In some embodiments the condensable hydrocarbon portion has a normal-C23 to total C23 weight ratio less than 0.43. Alternatively, the condensable hydrocarbon portion may have a normal-C23 to total C23 weight ratio less than 0.40, less than 0.35, or less than 0.29. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C23 to total C23 weight ratio greater than 0.15 or greater than 0.20. In some embodiments the condensable hydrocarbon portion has a normal-C24 to total C24 weight ratio less than 0.48. Alternatively, the condensable hydrocarbon portion may have a normal-C24 to total C24 weight ratio less than 0.46, less than 0.42, or less than 0.40. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C24 to total C24 weight ratio greater than 0.15 or greater than 0.20. In some embodiments the condensable hydrocarbon portion has a normal-C25 to total C25 weight ratio less than 0.48. Alternatively, the condensable hydrocarbon portion may have a normal-C25 to total C25 weight ratio less than 0.46, less than 0.42, or less than 0.40. In alternative embodiments, the condensable hydrocarbon portion may have a normal-C25 to total C25 weight ratio greater than 0.20 or greater than 0.25. Certain features of the present invention are described in terms of a set of numerical upper limits (e.g. “less than”) and a set of numerical lower limits (e.g. “greater than”) in the preceding paragraph. It should be appreciated that ranges formed by any combination of these limits are within the scope of the invention unless otherwise indicated. The embodiments described in this paragraph may be combined with any of the other aspects of the invention discussed herein.

The use of “total C_” (e.g., total C10) herein and in the claims is meant to refer to the amount of a particular pseudo component found in a condensable hydrocarbon fluid determined as described herein, particularly as described in the section labeled “Experiments” herein. That is “total C_” is determined using the whole oil gas chromatography (WOGC) analysis methodology according to the procedure described in the Experiments section of this application. Further, “total C_” is determined from the whole oil gas chromatography (WOGC) peak integration methodology and peak identification methodology used for identifying and quantifying each pseudo-component as described in the Experiments section herein. Further, “total C_” weight percent and mole percent values for the pseudo components were obtained using the pseudo component analysis methodology involving correlations developed by Katz and Firoozabadi (Katz, D. L., and A. Firoozabadi, 1978. Predicting phase behavior of condensate/crude-oil systems using methane interaction coefficients, J. Petroleum Technology (November 1978), 1649-1655) as described in the Experiments section, including the exemplary molar and weight percentage determinations.

The use of “normal-C_” (e.g., normal-C10) herein and in the claims is meant to refer to the amount of a particular normal alkane hydrocarbon compound found in a condensable hydrocarbon fluid determined as described herein, particularly in the section labeled “Experiments” herein. That is “normal-C_” is determined from the GC peak areas determined using the whole oil gas chromatography (WOGC) analysis methodology according to the procedure described in the Experiments section of this application. Further, “total C_” is determined from the whole oil gas chromatography (WOGC) peak identification and integration methodology used for identifying and quantifying individual compound peaks as described in the Experiments section herein. Further, “normal-C_” weight percent and mole percent values for the normal alkane compounds were obtained using methodology analogous to the pseudo component exemplary molar and weight percentage determinations explained in the Experiments section, except that the densities and molecular weights for the particular normal alkane compound of interest were used and then compared to the totals obtained in the pseudo component methodology to obtain weight and molar percentages.

The following discussion of FIG. 16 concerns data obtained in Examples 1-5 which are discussed in the section labeled “Experiments”. The data was obtained through the experimental procedures, gas sample collection procedures, hydrocarbon gas sample gas chromatography (GC) analysis methodology, and gas sample GC peak identification and integration methodology discussed in the Experiments section. For clarity, when referring to gas chromatograms of gaseous hydrocarbon samples, graphical data is provided for one unstressed experiment through Example 1, two 400 psi stressed experiments through Examples 2 and 3, and two 1,000 psi stressed experiments through Examples 4 and 5.

FIG. 16 is a bar graph showing the concentration, in molar percentage, of the hydrocarbon species present in the gas samples taken from each of the three stress levels tested and analyzed in the laboratory experiments discussed herein. The gas compound molar percentages were obtained through the experimental procedures, gas sample collection procedures, hydrocarbon gas sample gas chromatography (GC) analysis methodology, gas sample GC peak integration methodology and molar concentration determination procedures described herein. For clarity, the hydrocarbon molar percentages are taken as a percentage of the total of all identified hydrocarbon gas GC areas (i.e., methane, ethane, propane, iso-butane, n-butane, iso-pentane, n-pentane, 2-methyl pentane, and n-hexane) and calculated molar concentrations. Thus the graphed methane to normal C6 molar percentages for all of the experiments do not include the molar contribution of any associated non-hydrocarbon gas phase product (e.g., hydrogen, CO₂ or H₂S), any of the unidentified hydrocarbon gas species listed in Tables 2, 4, 5, 7, or 9 (e.g., peak numbers 2, 6, 8-11, 13, 15-22, 24-26, and 28-78 in Table 2) or any of the gas species dissolved in the liquid phase which were separately treated in the liquid GC's. The y-axis 3080 represents the concentration in terms of molar percent of each gaseous compound in the gas phase. The x-axis 3081 contains the identity of each hydrocarbon compound from methane to normal hexane. The bars 3082A-I represent the molar percentage of each gaseous compound for the unstressed experiment of Example 1. That is 3082A represents methane, 3082B represents ethane, 3082C represents propane, 3082D represents iso-butane, 3082E represents normal butane, 3082F represents iso-pentane, 3082G represents normal pentane, 3082H represents 2-methyl pentane, and 3082I represents normal hexane. The bars 3083A-I and 3084A-I represent the molar percent of each gaseous compound for samples from the duplicate 400 psi stressed experiments of Examples 2 and 3, with the letters assigned in the manner described for the unstressed experiment. While the bars 3085A-I and 3086A-I represent the molar percent of each gaseous compound for the duplicate 1,000 psi stressed experiments of Examples 4 and 5, with the letters assigned in the manner described for the unstressed experiment. From FIG. 16 it can be seen that the hydrocarbon gas produced in all the experiments is primarily methane, ethane and propane on a molar basis. It is further apparent that the unstressed experiment, represented by bars 3082A-I, contains the most methane 3082A and least propane 3082C, both as compared to the 400 psi stress experiments hydrocarbon gases and the 1,000 psi stress experiments hydrocarbon gases. Looking now at bars 3083A-I and 3084A-I, it is apparent that the intermediate level 400 psi stress experiments produced a hydrocarbon gas having methane 3083A and 3084A and propane 3083C and 3084C concentrations between the unstressed experiment represented by bars 3082A and 3082C and the 1,000 psi stressed experiment represented by bars 3085A and 3085C and 3086A and 3086C. Lastly, it is apparent that the high level 1,000 psi stress experiments produced hydrocarbon gases having the lowest methane 3085A and 3086A concentration and the highest propane concentrations 3085C and 3086C, as compared to both the unstressed experiments represented by bars 3082A and 3082C and the 400 psi stressed experiment represented by bars 3083A and 3084A and 3083C and 3084C. Thus pyrolyzing oil shale under increasing levels of lithostatic stress appears to produce hydrocarbon gases having decreasing concentrations of methane and increasing concentrations of propane.

The hydrocarbon fluid produced from the organic-rich rock formation may include both a condensable hydrocarbon portion (e.g. liquid) and a non-condensable hydrocarbon portion (e.g. gas). In some embodiments the non-condensable hydrocarbon portion includes methane and propane. In some embodiments the molar ratio of propane to methane in the non-condensable hydrocarbon portion is greater than 0.32. In alternative embodiments, the molar ratio of propane to methane in the non-condensable hydrocarbon portion is greater than 0.34, 0.36 or 0.38. As used herein “molar ratio of propane to methane” is the molar ratio that may be determined as described herein, particularly as described in the section labeled “Experiments” herein. That is “molar ratio of propane to methane” is determined using the hydrocarbon gas sample gas chromatography (GC) analysis methodology, gas sample GC peak identification and integration methodology and molar concentration determination procedures described in the Experiments section of this application.

In some embodiments the condensable hydrocarbon portion of the hydrocarbon fluid includes benzene. In some embodiments the condensable hydrocarbon portion has a benzene content between 0.1 and 0.8 weight percent. Alternatively, the condensable hydrocarbon portion may have a benzene content between 0.15 and 0.6 weight percent, a benzene content between 0.15 and 0.5, or a benzene content between 0.15 and 0.5.

In some embodiments the condensable hydrocarbon portion of the hydrocarbon fluid includes cyclohexane. In some embodiments the condensable hydrocarbon portion has a cyclohexane content less than 0.8 weight percent. Alternatively, the condensable hydrocarbon portion may have a cyclohexane content less than 0.6 weight percent or less than 0.43 weight percent. Alternatively, the condensable hydrocarbon portion may have a cyclohexane content greater than 0.1 weight percent or greater than 0.2 weight percent.

In some embodiments the condensable hydrocarbon portion of the hydrocarbon fluid includes methyl-cyclohexane. In some embodiments the condensable hydrocarbon portion has a methyl-cyclohexane content greater than 0.5 weight percent. Alternatively, the condensable hydrocarbon portion may have a methyl-cyclohexane content greater than 0.7 weight percent or greater than 0.75 weight percent. Alternatively, the condensable hydrocarbon portion may have a methyl-cyclohexane content less than 1.2 or 1.0 weight percent.

The use of weight percentage contents of benzene, cyclohexane, and methyl-cyclohexane herein and in the claims is meant to refer to the amount of benzene, cyclohexane, and methyl-cyclohexane found in a condensable hydrocarbon fluid determined as described herein, particularly as described in the section labeled “Experiments” herein. That is, respective compound weight percentages are determined from the whole oil gas chromatography (WOGC) analysis methodology and whole oil gas chromatography (WOGC) peak identification and integration methodology discussed in the Experiments section herein. Further, the respective compound weight percentages were obtained as described for FIG. 11, except that each individual respective compound peak area integration was used to determine each respective compound weight percentage. For clarity, the compound weight percentages are taken as a percentage of the entire C3 to pseudo C38 whole oil gas chromatography areas and calculated weights as used in the pseudo compound data presented in FIG. 7.

In some embodiments the condensable hydrocarbon portion of the hydrocarbon fluid has an API gravity greater than 30. Alternatively, the condensable hydrocarbon portion may have an API gravity greater than 30, 32, 34, 36, 40, 42 or 44. As used herein and in the claims, API gravity may be determined by any generally accepted method for determining API gravity.

In some embodiments the condensable hydrocarbon portion of the hydrocarbon fluid has a basic nitrogen to total nitrogen ratio between 0.1 and 0.50. Alternatively, the condensable hydrocarbon portion may have a basic nitrogen to total nitrogen ratio between 0.15 and 0.40. As used herein and in the claims, basic nitrogen and total nitrogen may be determined by any generally accepted method for determining basic nitrogen and total nitrogen. Where results conflict, the generally accepted more accurate methodology shall control.

The discovery that lithostatic stress can affect the composition of produced fluids generated within an organic-rich rock via heating and pyrolysis implies that the composition of the produced hydrocarbon fluid can also be influenced by altering the lithostatic stress of the organic-rich rock formation. For example, the lithostatic stress of the organic-rich rock formation may be altered by choice of pillar geometries and/or locations and/or by choice of heating and pyrolysis formation region thickness and/or heating sequencing.

Pillars are regions within the organic-rich rock formation left unpyrolyzed at a given time to lessen or mitigate surface subsidence. Pillars may be regions within a formation surrounded by pyrolysis regions within the same formation. Alternatively, pillars may be part of or connected to the unheated regions outside the general development area. Certain regions that act as pillars early in the life of a producing field may be converted to producing regions later in the life of the field.

Typically in its natural state, the weight of a formation's overburden is fairly uniformly distributed over the formation. In this state the lithostatic stress existing at particular point within a formation is largely controlled by the thickness and density of the overburden. A desired lithostatic stress may be selected by analyzing overburden geology and choosing a position with an appropriate depth and position.

Although lithostatic stresses are commonly assumed to be set by nature and not changeable short of removing all or part of the overburden, lithostatic stress at a specific location within a formation can be adjusted by redistributing the overburden weight so it is not uniformly supported by the formation. For example, this redistribution of overburden weight may be accomplished by two exemplary methods. One or both of these methods may be used within a single formation. In certain cases, one method may be primarily used earlier in time whereas the other may be primarily used at a later time. Favorably altering the lithostatic stress experienced by a formation region may be performed prior to instigating significant pyrolysis within the formation region and also before generating significant hydrocarbon fluids. Alternately, favorably altering the lithostatic stress may be performed simultaneously with the pyrolysis.

A first method of altering lithostatic stress involves making a region of a subsurface formation less stiff than its neighboring regions. Neighboring regions thus increasingly act as pillars supporting the overburden as a particular region becomes less stiff. These pillar regions experience increased lithostatic stress whereas the less stiff region experience reduced lithostatic stress. The amount of change in lithostatic stress depends upon a number of factors including, for example, the change in stiffness of the treated region, the size of the treated region, the pillar size, the pillar spacing, the rock compressibility, and the rock strength. In an organic-rich rock formation, a region within a formation may be made to experience mechanical weakening by pyrolyzing the region and creating void space within the region by removing produced fluids. In this way a region within a formation may be made less stiff than neighboring regions that have not experienced pyrolysis or have experienced a lesser degree of pyrolysis or production.

A second method of altering lithostatic stress involves causing a region of a subsurface formation to expand and push against the overburden with greater force than neighboring regions. This expansion may remove a portion of the overburden weight from the neighboring regions thus increasing the lithostatic stress experienced by the heated region and reducing the lithostatic stress experienced by neighboring regions. If the expansion is sufficient, horizontal fractures will form in the neighboring regions and the contribution of these regions to supporting the overburden will decrease. The amount of change in lithostatic stress depends upon a number of factors including, for example, the amount of expansion in the treated region, the size of the treated region, the pillar size, the pillar spacing, the rock compressibility, and the rock strength. A region within a formation may be made to expand by heating it so to cause thermal expansion of the rock. Fluid expansion or fluid generation can also contribute to expansion if the fluids are largely trapped within the region. The total expansion amount may be proportional to the thickness of the heated region. It is noted that if pyrolysis occurs in the heated region and sufficient fluids are removed, the heated region may mechanically weaken and thus may alter the lithostatic stresses experienced by the neighboring regions as described in the first exemplary method.

Embodiments of the method may include controlling the composition of produced hydrocarbon fluids generated by heating and pyrolysis from a first region within an organic-rich rock formation by increasing the lithostatic stresses within the first region by first heating and pyrolyzing formation hydrocarbons present in the organic-rich rock formation and producing fluids from a second neighboring region within the organic-rich rock formation such that the Young's modulus (i.e., stiffness) of the second region is reduced.

Embodiments of the method may include controlling the composition of produced hydrocarbon fluids generated by heating and pyrolysis from a first region within an organic-rich rock formation by increasing the lithostatic stresses within the first region by heating the first region prior to or to a greater degree than neighboring regions within the organic-rich rock formation such that the thermal expansion within the first region is greater than that within the neighboring regions of the organic-rich rock formation.

Embodiments of the method may include controlling the composition of produced hydrocarbon fluids generated by heating and pyrolysis from a first region within an organic-rich rock formation by decreasing the lithostatic stresses within the first region by heating one or more neighboring regions of the organic-rich rock formation prior to or to a greater degree than the first region such that the thermal expansion within the neighboring regions is greater than that within the first region.

Embodiments of the method may include locating, sizing, and/or timing the heating of heated regions within an organic-rich rock formation so as to alter the in situ lithostatic stresses of current or future heating and pyrolysis regions within the organic-rich rock formation so as to control the composition of produced hydrocarbon fluids.

Some production procedures include in situ heating of an organic-rich rock formation that contains both formation hydrocarbons and formation water-soluble minerals prior to substantial removal of the formation water-soluble minerals from the organic-rich rock formation. In some embodiments of the invention there is no need to partially, substantially or completely remove the water-soluble minerals prior to in situ heating. For example, in an oil shale formation that contains naturally occurring nahcolite, the oil shale may be heated prior to substantial removal of the nahcolite by solution mining. Substantial removal of a water-soluble mineral may represent the degree of removal of a water-soluble mineral that occurs from any commercial solution mining operation as known in the art. Substantial removal of a water-soluble mineral may be approximated as removal of greater than 5 weight percent of the total amount of a particular water-soluble mineral present in the zone targeted for hydrocarbon fluid production in the organic-rich rock formation. In alternative embodiments, in situ heating of the organic-rich rock formation to pyrolyze formation hydrocarbons may be commenced prior to removal of greater than 3 weight percent, alternatively 7 weight percent, 10 weight percent or 13 weight percent of the formation water-soluble minerals from the organic-rich rock formation.

The impact of heating oil shale to produce oil and gas prior to producing nahcolite is to convert the nahcolite to a more recoverable form (soda ash), and provide permeability facilitating its subsequent recovery. Water-soluble mineral recovery may take place as soon as the retorted oil is produced, or it may be left for a period of years for later recovery. If desired, the soda ash can be readily converted back to nahcolite on the surface. The ease with which this conversion can be accomplished makes the two minerals effectively interchangeable.

In some production processes, heating the organic-rich rock formation includes generating soda ash by decomposition of nahcolite. The method may include processing an aqueous solution containing water-soluble minerals in a surface facility to remove a portion of the water-soluble minerals. The processing step may include removing the water-soluble minerals by precipitation caused by altering the temperature of the aqueous solution.

The water-soluble minerals may include sodium. The water-soluble minerals may also include nahcolite (sodium bicarbonate), soda ash (sodium carbonate), dawsonite (NaAl)(CO₃)(OH)₂), or combinations thereof. The surface processing may further include converting the soda ash back to sodium bicarbonate (nahcolite) in the surface facility by reaction with CO₂. After partial or complete removal of the water-soluble minerals, the aqueous solution may be reinjected into a subsurface formation where it may be sequestered. The subsurface formation may be the same as or different from the original organic-rich rock formation.

In some production processes, heating of the organic-rich rock formation both pyrolyzes at least a portion of the formation hydrocarbons to create hydrocarbon fluids and makes available migratory contaminant species previously bound in the organic-rich rock formation. The migratory contaminant species may be formed through pyrolysis of the formation hydrocarbons, may be liberated from the formation itself upon heating, or may be made accessible through the creation of increased permeability upon heating of the formation. The migratory contaminant species may be soluble in water or other aqueous fluids present in or injected into the organic-rich rock formation.

Producing hydrocarbons from pyrolyzed oil shale will generally leave behind some migratory contaminant species which are at least partially water-soluble. Depending on the hydrological connectivity of the pyrolyzed shale oil to shallower zones, these components may eventually migrate into ground water in concentrations which are environmentally unacceptable. The types of potential migratory contaminant species depend on the nature of the oil shale pyrolysis and the composition of the oil shale being converted. If the pyrolysis is performed in the absence of oxygen or air, the contaminant species may include aromatic hydrocarbons (e.g. benzene, toluene, ethylbenzene, xylenes), polyaromatic hydrocarbons (e.g. anthracene, pyrene, naphthalene, chrysene), metal contaminants (e.g. As, Co, Pb, Mo, Ni, and Zn), and other species such as sulfates, ammonia, Al, K, Mg, chlorides, flourides and phenols. If oxygen or air is employed, contaminant species may also include ketones, alcohols, and cyanides. Further, the specific migratory contaminant species present may include any subset or combination of the above-described species.

It may be desirable for a field developer to assess the connectivity of the organic-rich rock formation to aquifers. This may be done to determine if, or to what extent, in situ pyrolysis of formation hydrocarbons in the organic-rich rock formation may create migratory species with the propensity to migrate into an aquifer. If the organic-rich rock formation is hydrologically connected to an aquifer, precautions may be taken to reduce or prevent species generated or liberated during pyrolysis from entering the aquifer. Alternatively, the organic-rich rock formation may be flushed with water or an aqueous fluid after pyrolysis as described herein to remove water-soluble minerals and/or migratory contaminant species. In other embodiments, the organic-rich rock formation may be substantially hydrologically unconnected to any source of ground water. In such a case, flushing the organic-rich rock formation may not be desirable for removal of migratory contaminant species but may nevertheless be desirable for recovery of water-soluble minerals.

Following production of hydrocarbons from an organic-rich formation, some migratory contaminant species may remain in the rock formation. In such case, it may be desirable to inject an aqueous fluid into the organic-rich rock formation and have the injected aqueous fluid dissolve at least a portion of the water-soluble minerals and/or the migratory contaminant species to form an aqueous solution. The aqueous solution may then be produced from the organic-rich rock formation through, for example, solution production wells. The aqueous fluid may be adjusted to increase the solubility of the migratory contaminant species and/or the water-soluble minerals. The adjustment may include the addition of an acid or base to adjust the pH of the solution. The resulting aqueous solution may then be produced from the organic-rich rock formation to the surface for processing.

After initial aqueous fluid production, it may further be desirable to flush the matured organic-rich rock zone and the unmatured organic-rich rock zone with an aqueous fluid. The aqueous fluid may be used to further dissolve water-soluble minerals and migratory contaminant species. The flushing may optionally be completed after a substantial portion of the hydrocarbon fluids have been produced from the matured organic-rich rock zone. In some embodiments, the flushing step may be delayed after the hydrocarbon fluid production step. The flushing may be delayed to allow heat generated from the heating step to migrate deeper into surrounding unmatured organic-rich rock zones to convert nahcolite within the surrounding unmatured organic-rich rock zones to soda ash. Alternatively, the flushing may be delayed to allow heat generated from the heating step to generate permeability within the surrounding unmatured organic-rich rock zones. Further, the flushing may be delayed based on current and/or forecast market prices of sodium bicarbonate, soda ash, or both as further discussed herein. This method may be combined with any of the other aspects of the invention as discussed herein.

Upon flushing of an aqueous solution, it may be desirable to process the aqueous solution in a surface facility to remove at least some of the migratory contaminant species. The migratory contaminant species may be removed through use of, for example, an adsorbent material, reverse osmosis, chemical oxidation, bio-oxidation, and/or ion exchange. Examples of these processes are individually known in the art. Exemplary adsorbent materials may include activated carbon, clay, or fuller's earth.

In certain areas with oil shale resources, additional oil shale resources or other hydrocarbon resources may exist at lower depths. Other hydrocarbon resources may include natural gas in low permeability formations (so-called “tight gas”) or natural gas trapped in and adsorbed on coal (so called “coalbed methane”). In some embodiments with multiple oil shale resources it may be advantageous to develop deeper zones first and then sequentially shallower zones. In this way, wells will need not cross hot zones or zones of weakened rock. In other embodiments in may be advantageous to develop deeper zones by drilling wells through regions being utilized as pillars for shale oil development at a shallower depth.

Simultaneous development of shale oil resources and natural gas resources in the same area can synergistically utilize certain facility and logistic operations. For example, gas treating may be performed at a single plant. Likewise personnel may be shared among the developments.

FIG. 6 illustrates a schematic diagram of an embodiment of surface facilities 70 that may be configured to treat a produced fluid. The produced fluid 85 may be produced from the subsurface formation 84 though a production well 71 as described herein. The produced fluid may include any of the produced fluids produced by any of the methods as described herein. The subsurface formation 84 may be any subsurface formation, including, for example, an organic-rich rock formation containing any of oil shale, coal, or tar sands for example. A production scheme may involve quenching 72 produced fluids to a temperature below 300° F., 200° F., or even 100° F., separating out condensable components (i.e., oil 74 and water 75) in an oil separator 73, treating the noncondensable components 76 (i.e. gas) in a gas treating unit 77 to remove water 78 and sulfur species 79, removing the heavier components from the gas (e.g., propane and butanes) in a gas plant 81 to form liquid petroleum gas (LPG) 80 for sale, and generating electrical power 82 in a power plant 88 from the remaining gas 83. The electrical power 82 may be used as an energy source for heating the subsurface formation 84 through any of the methods described herein. For example, the electrical power 82 may be feed at a high voltage, for example 132 kV, to a transformer 86 and let down to a lower voltage, for example 6600 V, before being fed to an electrical resistance heater element located in a heater well 87 located in the subsurface formation 84. In this way all or a portion of the power required to heat the subsurface formation 84 may be generated from the non-condensable portion of the produced fluids 85. Excess gas, if available, may be exported for sale.

Produced fluids from in situ oil shale production contain a number of components which may be separated in surface facilities. The produced fluids typically contain water, noncondensable hydrocarbon alkane species (e.g., methane, ethane, propane, n-butane, isobutane), noncondensable hydrocarbon alkene species (e.g., ethene, propene), condensable hydrocarbon species composed of (alkanes, olefins, aromatics, and polyaromatics among others), CO₂, CO, H₂, H₂S, and NH₃.

In a surface facility, condensable components may be separated from non-condensable components by reducing temperature and/or increasing pressure. Temperature reduction may be accomplished using heat exchangers cooled by ambient air or available water. Alternatively, the hot produced fluids may be cooled via heat exchange with produced hydrocarbon fluids previously cooled. The pressure may be increased via centrifugal or reciprocating compressors. Alternatively, or in conjunction, a diffuser-expander apparatus may be used to condense out liquids from gaseous flows. Separations may involve several stages of cooling and/or pressure changes.

Water in addition to condensable hydrocarbons may be dropped out of the gas when reducing temperature or increasing pressure. Liquid water may be separated from condensable hydrocarbons via gravity settling vessels or centrifugal separators. Demulsifiers may be used to aid in water separation.

Methods to remove CO₂, as well as other so-called acid gases (such as H₂S), from produced hydrocarbon gas include the use of chemical reaction processes and of physical solvent processes. Chemical reaction processes typically involve contacting the gas stream with an aqueous amine solution at high pressure and/or low temperature. This causes the acid gas species to chemically react with the amines and go into solution. By raising the temperature and/or lowering the pressure, the chemical reaction can be reversed and a concentrated stream of acid gases can be recovered. An alternative chemical reaction process involves hot carbonate solutions, typically potassium carbonate. The hot carbonate solution is regenerated and the concentrated stream of acid gases is recovered by contacting the solution with steam. Physical solvent processes typically involve contacting the gas stream with a glycol at high pressure and/or low temperature. Like the amine processes, reducing the pressure or raising the temperature allows regeneration of the solvent and recovery of the acid gases. Certain amines or glycols may be more or less selective in the types of acid gas species removed. Sizing of any of these processes requires determining the amount of chemical to circulate, the rate of circulation, the energy input for regeneration, and the size and type of gas-chemical contacting equipment. Contacting equipment may include packed or multi-tray countercurrent towers. Optimal sizing for each of these aspects is highly dependent on the rate at which gas is being produced from the formation and the concentration of the acid gases in the gas stream.

Acid gas removal may also be effectuated through the use of distillation towers. Such towers may include an intermediate freezing section wherein frozen CO₂ and H₂S particles are allowed to form. A mixture of frozen particles and liquids fall downward into a stripping section, where the lighter hydrocarbon gasses break out and rise within the tower. A rectification section may be provided at an upper end of the tower to further facilitate the cleaning of the overhead gas stream.

The hydrogen content of a gas stream may be adjusted by either removing all or a portion, of the hydrogen or by removing all or a portion of the non-hydrogen species (e.g., CO₂, CH₄, etc.) Separations may be accomplished using cryogenic condensation, pressure-swing or temperature-swing adsorption, or selective diffusion membranes. If additional hydrogen is needed, hydrogen may be made by reforming methane via the classic water-shift reaction.

Experiments

Heating experiments were conducted on several different oil shale specimens and the liquids and gases released from the heated oil shale examined in detail. An oil shale sample from the Mahogany formation in the Piceance Basin in Colorado was collected. A solid, continuous block of the oil shale formation, approximately 1 cubic foot in size, was collected from the pilot mine at the Colony mine site on the eastern side of Parachute Creek. The oil shale block was designated CM-1B. The core specimens taken from this block, as described in the following examples, were all taken from the same stratigraphic interval. The heating tests were conducted using a Parr vessel, model number 243HC5, which is shown in FIG. 18 and is available from Parr Instrument Company.

Example 1

Oil shale block CM-1B was cored across the bedding planes to produce a cylinder 1.391 inches in diameter and approximately 2 inches long. A gold tube 7002 approximately 2 inches in diameter and 5 inches long was crimped and a screen 7000 inserted to serve as a support for the core specimen 7001 (FIG. 17). The oil shale core specimen 7001, 82.46 grams in weight, was placed on the screen 7000 in the gold tube 7002 and the entire assembly placed into a Parr heating vessel. The Parr vessel 7010, shown in FIG. 18, had an internal volume of 565 milliliters. Argon was used to flush the Parr vessel 7010 several times to remove air present in the chamber and the vessel pressurized to 500 psi with argon. The Parr vessel was then placed in a furnace which was designed to fit the Parr vessel. The furnace was initially at room temperature and was heated to 400° C. after the Parr vessel was placed in the furnace. The temperature of the Parr vessel achieved 400° C. after about 3 hours and remained in the 400° C. furnace for 24 hours. The Parr vessel was then removed from the furnace and allowed to cool to room temperature over a period of approximately 16 hours.

The room temperature Parr vessel was sampled to obtain a representative portion of the gas remaining in the vessel following the heating experiment. A small gas sampling cylinder 150 milliliters in volume was evacuated, attached to the Parr vessel and the pressure allowed to equilibrate. Gas chromatography (GC) analysis testing and non-hydrocarbon gas sample gas chromatography (GC) (GC not shown) of this gas sample yielded the results shown in FIG. 19, Table 2 and Table 1. In FIG. 19 the y-axis 4000 represents the detector response in pico-amperes (pA) while the x-axis 4001 represents the retention time in minutes. In FIG. 19 peak 4002 represents the response for methane, peak 4003 represents the response for ethane, peak 4004 represents the response for propane, peak 4005 represents the response for butane, peak 4006 represents the response for pentane and peak 4007 represents the response for hexane. From the GC results and the known volumes and pressures involved the total hydrocarbon content of the gas (2.09 grams), CO₂ content of the gas (3.35 grams), and H2S content of the gas (0.06 gram) were obtained.

TABLE 2 Peak and Area Details for FIG. 19 - Example 1 - 0 psi stress - Gas GC Peak Ret. Time Area Compound Number [min] [pA * s] Name 1 0.910 1.46868e4 Methane 2 0.999 148.12119 ? 3 1.077 1.26473e4 Ethane 4 2.528 1.29459e4 Propane 5 4.243 2162.93066 iC4 6 4.922 563.11804 ? 7 5.022 5090.54150 n-Butane 8 5.301 437.92255 ? 9 5.446 4.67394 ? 10 5.582 283.92194 ? 11 6.135 15.47334 ? 12 6.375 1159.83130 iC5 13 6.742 114.83960 ? 14 6.899 1922.98450 n-Pentane 15 7.023 2.44915 ? 16 7.136 264.34424 ? 17 7.296 127.60601 ? 18 7.383 118.79453 ? 19 7.603 3.99227 ? 20 8.138 13.15432 ? 21 8.223 13.01887 ? 22 8.345 103.15615 ? 23 8.495 291.26767 2-methyl pentane 24 8.651 15.64066 ? 25 8.884 91.85989 ? 26 9.165 40.09448 ? 27 9.444 534.44507 n-Hexane 28 9.557 2.64731 ? 29 9.650 32.28295 ? 30 9.714 52.42796 ? 31 9.793 42.05001 ? 32 9.852 8.93775 ? 33 9.914 4.43648 ? 34 10.013 24.74299 ? 35 10.229 13.34387 ? 36 10.302 133.95892 ? 37 10.577 2.67224 ? 38 11.252 27.57400 ? 39 11.490 23.41665 ? 40 11.567 8.13992 ? 41 11.820 32.80781 ? 42 11.945 4.61821 ? 43 12.107 30.67044 ? 44 12.178 2.58269 ? 45 12.308 13.57769 ? 46 12.403 12.43018 ? 47 12.492 34.29918 ? 48 12.685 4.71311 ? 49 12.937 183.31729 ? 50 13.071 7.18510 ? 51 13.155 2.01699 ? 52 13.204 7.77467 ? 53 13.317 7.21400 ? 54 13.443 4.22721 ? 55 13.525 35.08374 ? 56 13.903 18.48654 ? 57 14.095 6.39745 ? 58 14.322 3.19935 ? 59 14.553 8.48772 ? 60 14.613 3.34738 ? 61 14.730 5.44062 ? 62 14.874 40.17010 ? 63 14.955 3.41596 ? 64 15.082 3.04766 ? 65 15.138 7.33028 ? 66 15.428 2.71734 ? 67 15.518 11.00256 ? 68 15.644 5.16752 ? 69 15.778 45.12025 ? 70 15.855 3.26920 ? 71 16.018 3.77424 ? 72 16.484 4.66657 ? 73 16.559 5.54783 ? 74 16.643 10.57255 ? 75 17.261 2.19534 ? 76 17.439 10.26123 ? 77 17.971 1.85618 ? 78 18.097 11.42077 ?

The Parr vessel was then vented to achieve atmospheric pressure, the vessel opened, and liquids collected from both inside the gold tube and in the bottom of the Parr vessel. Water was separated from the hydrocarbon layer and weighed. The amount collected is noted in Table 1. The collected hydrocarbon liquids were placed in a small vial, sealed and stored in the absence of light. No solids were observed on the walls of the gold tube or the walls of the Parr vessel. The solid core specimen was weighed and determined to have lost 19.21 grams as a result of heating. Whole oil gas chromatography (WOGC) testing of the liquid yielded the results shown in FIG. 20, Table 3, and Table 1. In FIG. 20 the y-axis 5000 represents the detector response in pico-amperes (pA) while the x-axis 5001 represents the retention time in minutes. The GC chromatogram is shown generally by label 5002 with individual identified peaks labeled with abbreviations.

TABLE 3 Peak and Area Details for FIG. 20 - Example 1 - 0 psi stress - Liquid GC Peak Ret. Time Peak Area Compound Number [min] [pA * s] Name  1 2.660 119.95327 iC4  2 2.819 803.25989 nC4  3 3.433 1091.80298 iC5  4 3.788 2799.32520 nC5  5 5.363 1332.67871 2-methyl pentane (2MP)  6 5.798 466.35703 3-methyl pentane (3MP)  7 6.413 3666.46240 nC6  8 7.314 1161.70435 Methyl cyclopentane (MCP)  9 8.577 287.05969 Benzene (BZ) 10 9.072 530.19781 Cyclohexane (CH) 11 10.488 4700.48291 nC7 12 11.174 937.38757 Methyl cyclohexane (MCH) 13 12.616 882.17358 Toluene (TOL) 14 14.621 3954.29687 nC8 15 18.379 3544.52905 nC9 16 21.793 3452.04199 nC10 17 24.929 3179.11841 nC11 18 27.843 2680.95459 nC12 19 30.571 2238.89600 nC13 20 33.138 2122.53540 nC14 21 35.561 1773.59973 nC15 22 37.852 1792.89526 nC16 23 40.027 1394.61707 nC17 24 40.252 116.81663 Pristane (Pr) 25 42.099 1368.02734 nC18 26 42.322 146.96437 Phytane (Ph) 27 44.071 1130.63342 nC19 28 45.956 920.52136 nC20 29 47.759 819.92810 nC21 30 49.483 635.42065 nC22 31 51.141 563.24316 nC23 32 52.731 432.74606 nC24 33 54.261 397.36270 nC25 34 55.738 307.56073 nC26 35 57.161 298.70926 nC27 36 58.536 252.60083 nC28 37 59.867 221.84540 nC29 38 61.154 190.29596 nC30 39 62.539 123.65781 nC31 40 64.133 72.47668 nC32 41 66.003 76.84142 nC33 42 68.208 84.35004 nC34 43 70.847 36.68131 nC35 44 74.567 87.62341 nC36 45 77.798 33.30892 nC37 46 82.361 21.99784 nC38 Totals: 5.32519e4

Example 2

Oil shale block CM-1B was cored in a manner similar to that of Example 1 except that a 1 inch diameter core was created. With reference to FIG. 21, the core specimen 7050 was approximately 2 inches in length and weighed 42.47 grams. This core specimen 7050 was placed in a Berea sandstone cylinder 7051 with a 1-inch inner diameter and a 1.39 inch outer diameter. Berea plugs 7052 and 7053 were placed at each end of this assembly, so that the core specimen was completely surrounded by Berea. The Berea cylinder 7051 along with the core specimen 7050 and the Berea end plugs 7052 and 7053 were placed in a slotted stainless steel sleeve and clamped into place. The sample assembly 7060 was placed in a spring-loaded mini-load-frame 7061 as shown in FIG. 22. Load was applied by tightening the nuts 7062 and 7063 at the top of the load frame 7061 to compress the springs 7064 and 7065. The springs 7064 and 7065 were high temperature, Inconel springs, which delivered 400 psi effective stress to the oil shale specimen 7060 when compressed. Sufficient travel of the springs 7064 and 7065 remained in order to accommodate any expansion of the core specimen 7060 during the course of heating. In order to ensure that this was the case, gold foil 7066 was placed on one of the legs of the apparatus to gauge the extent of travel. The entire spring loaded apparatus 7061 was placed in the Parr vessel (FIG. 18) and the heating experiment conducted as described in Example 1.

As described in Example 1, the room temperature Parr vessel was then sampled to obtain a representative portion of the gas remaining in the vessel following the heating experiment. Gas sampling, hydrocarbon gas sample gas chromatography (GC) testing, and non-hydrocarbon gas sample gas chromatography (GC) was conducted as in Example 1. Results are shown in FIG. 23, Table 4 and Table 1. In FIG. 23 the y-axis 4010 represents the detector response in pico-amperes (pA) while the x-axis 4011 represents the retention time in minutes. In FIG. 23 peak 4012 represents the response for methane, peak 4013 represents the response for ethane, peak 4014 represents the response for propane, peak 4015 represents the response for butane, peak 4016 represents the response for pentane and peak 4017 represents the response for hexane. From the gas chromatographic results and the known volumes and pressures involved the total hydrocarbon content of the gas was determined to be 1.33 grams and CO₂ content of the gas was 1.70 grams.

TABLE 4 Peak and Area Details for FIG. 23 - Example 2 - 400 psi stress - Gas GC Peak Ret. Time Area Compound Number [min] [pA * s] Name 1 0.910 1.36178e4 Methane 2 0.999 309.65613 ? 3 1.077 1.24143e4 Ethane 4 2.528 1.41685e4 Propane 5 4.240 2103.01929 iC4 6 4.917 1035.25513 ? 7 5.022 5689.08887 n-Butane 8 5.298 450.26572 ? 9 5.578 302.56229 ? 10 6.125 33.82201 ? 11 6.372 1136.37097 iC5 12 6.736 263.35754 ? 13 6.898 2254.86621 n-Pentane 14 7.066 7.12101 ? 15 7.133 258.31876 ? 16 7.293 126.54671 ? 17 7.378 155.60977 ? 18 7.598 6.73467 ? 19 7.758 679.95312 ? 20 8.133 27.13466 ? 21 8.216 24.77329 ? 22 8.339 124.70064 ? 23 8.489 289.12952 2-methyl pentane 24 8.644 19.83309 ? 25 8.878 92.18938 ? 26 9.184 102.25701 ? 27 9.438 664.42584 n-Hexane 28 9.549 2.91525 ? 29 9.642 26.86672 ? 30 9.705 49.83235 ? 31 9.784 52.11239 ? 32 9.843 9.03158 ? 33 9.904 6.18217 ? 34 10.004 24.84150 ? 35 10.219 13.21182 ? 36 10.292 158.67511 ? 37 10.411 2.49094 ? 38 10.566 3.25252 ? 39 11.240 46.79988 ? 40 11.478 29.59438 ? 41 11.555 12.84377 ? 42 11.809 38.67433 ? 43 11.935 5.68525 ? 44 12.096 31.29068 ? 45 12.167 5.84513 ? 46 12.297 15.52042 ? 47 12.393 13.54158 ? 48 12.483 30.95983 ? 49 12.669 20.21915 ? 50 12.929 229.00655 ? 51 13.063 6.38678 ? 52 13.196 10.89876 ? 53 13.306 7.91553 ? 54 13.435 5.05444 ? 55 13.516 44.42806 ? 56 13.894 20.61910 ? 57 14.086 8.32365 ? 58 14.313 2.80677 ? 59 14.545 9.18198 ? 60 14.605 4.93703 ? 61 14.722 5.06628 ? 62 14.865 46.53282 ? 63 14.946 6.55945 ? 64 15.010 2.85594 ? 65 15.075 4.05371 ? 66 15.131 9.15954 ? 67 15.331 2.16523 ? 68 15.421 3.03294 ? 69 15.511 9.73797 ? 70 15.562 5.22962 ? 71 15.636 3.73105 ? 72 15.771 54.64651 ? 73 15.848 3.95764 ? 74 16.010 3.39639 ? 75 16.477 5.49586 ? 76 16.552 6.21470 ? 77 16.635 11.08140 ? 78 17.257 2.28673 ? 79 17.318 2.82284 ? 80 17.433 11.11376 ? 81 17.966 2.54065 ? 82 18.090 14.28333 ?

At this point, the Parr vessel was vented to achieve atmospheric pressure, the vessel opened, and liquids collected from inside the Parr vessel. Water was separated from the hydrocarbon layer and weighed. The amount collected is noted in Table 1. The collected hydrocarbon liquids were placed in a small vial, sealed and stored in the absence of light. Any additional liquid coating the surface of the apparatus or sides of the Parr vessel was collected with a paper towel and the weight of this collected liquid added to the total liquid collected. Any liquid remaining in the Berea sandstone was extracted with methylene chloride and the weight accounted for in the liquid total reported in Table 1. The Berea sandstone cylinder and end caps were clearly blackened with organic material as a result of the heating. The organic material in the Berea was not extractable with either toluene or methylene chloride, and was therefore determined to be coke formed from the cracking of hydrocarbon liquids. After the heating experiment, the Berea was crushed and its total organic carbon (TOC) was measured. This measurement was used to estimate the amount of coke in the Berea and subsequently how much liquid must have cracked in the Berea. A constant factor of 2.283 was used to convert the TOC measured to an estimate of the amount of liquid, which must have been present to produce the carbon found in the Berea. This liquid estimated is the “inferred oil” value shown in Table 1. The solid core specimen was weighed and determined to have lost 10.29 grams as a result of heating.

Example 3

Conducted in a manner similar to that of Example 2 on a core specimen from oil shale block CM-1B, where the effective stress applied was 400 psi. Results for the gas sample collected and analyzed by hydrocarbon gas sample gas chromatography (GC) and non-hydrocarbon gas sample gas chromatography (GC) (GC not shown) are shown in FIG. 24, Table 5 and Table 1. In FIG. 24 the y-axis 4020 represents the detector response in pico-amperes (pA) while the x-axis 4021 represents the retention time in minutes. In FIG. 24 peak 4022 represents the response for methane, peak 4023 represents the response for ethane, peak 4024 represents the response for propane, peak 4025 represents the response for butane, peak 4026 represents the response for pentane and peak 4027 represents the response for hexane. Results for the liquid collected and analyzed by whole oil gas chromatography (WOGC) analysis are shown in FIG. 25, Table 6 and Table 1. In FIG. 25 the y-axis 5050 represents the detector response in pico-amperes (pA) while the x-axis 5051 represents the retention time in minutes. The GC chromatogram is shown generally by label 5052 with individual identified peaks labeled with abbreviations.

TABLE 5 Peak and Area Details for FIG. 24 - Example 3 - 400 psi stress - Gas GC Peak Ret. Time Area Compound Number [min] [pA * s] Name 1 0.910 1.71356e4 Methane 2 0.998 341.71646 ? 3 1.076 1.52621e4 Ethane 4 2.534 1.72319e4 Propane 5 4.242 2564.04077 iC4 6 4.919 1066.90942 ? 7 5.026 6553.25244 n-Butane 8 5.299 467.88803 ? 9 5.579 311.65158 ? 10 6.126 33.61063 ? 11 6.374 1280.77869 iC5 12 6.737 250.05510 ? 13 6.900 2412.40918 n-Pentane 14 7.134 249.80679 ? 15 7.294 122.60424 ? 16 7.379 154.40988 ? 17 7.599 6.87471 ? 18 8.132 25.50270 ? 19 8.216 22.33015 ? 20 8.339 129.17023 ? 21 8.490 304.97903 2-methyl pentane 22 8.645 18.48411 ? 23 8.879 98.23043 ? 24 9.187 89.71329 ? 25 9.440 656.02161 n-Hexane 26 9.551 3.05892 ? 27 9.645 25.34058 ? 28 9.708 45.14915 ? 29 9.786 48.62077 ? 30 9.845 10.03335 ? 31 9.906 5.43165 ? 32 10.007 22.33582 ? 33 10.219 16.02756 ? 34 10.295 196.43715 ? 35 10.413 2.98115 ? 36 10.569 3.88067 ? 37 11.243 41.63386 ? 38 11.482 28.44063 ? 39 11.558 12.05196 ? 40 11.812 37.83630 ? 41 11.938 5.45990 ? 42 12.100 31.03111 ? 43 12.170 4.91053 ? 44 12.301 15.75041 ? 45 12.397 13.75454 ? 46 12.486 30.26099 ? 47 12.672 15.14775 ? 48 12.931 207.50433 ? 49 13.064 3.35393 ? 50 13.103 3.04880 ? 51 13.149 1.62203 ? 52 13.198 7.97665 ? 53 13.310 7.49605 ? 54 13.437 4.64921 ? 55 13.519 41.82572 ? 56 13.898 19.01739 ? 57 14.089 7.34498 ? 58 14.316 2.68912 ? 59 14.548 8.29593 ? 60 14.608 3.93147 ? 61 14.725 4.75483 ? 62 14.869 40.93447 ? 63 14.949 5.30140 ? 64 15.078 5.79979 ? 65 15.134 7.95179 ? 66 15.335 1.91589 ? 67 15.423 2.75893 ? 68 15.515 8.64343 ? 69 15.565 3.76481 ? 70 15.639 3.41854 ? 71 15.774 45.59035 ? 72 15.850 3.73501 ? 73 16.014 5.84199 ? 74 16.480 4.87036 ? 75 16.555 5.12607 ? 76 16.639 9.97469 ? 77 17.436 8.00434 ? 78 17.969 3.86749 ? 79 18.093 9.71661 ?

TABLE 6 Peak and Area Details from FIG. 25 - Example 3 - 400 psi stress - Liquid GC. Peak Ret. Time Peak Area Compound Number [min] [pA * s] Name  1 2.744 102.90978 iC4  2 2.907 817.57861 nC4  3 3.538 1187.01831 iC5  4 3.903 3752.84326 nC5  5 5.512 1866.25342 2MP  6 5.950 692.18964 3MP  7 6.580 6646.48242 nC6  8 7.475 2117.66919 MCP  9 8.739 603.21204 BZ 10 9.230 1049.96240 CH 11 10.668 9354.29590 nC7 12 11.340 2059.10303 MCH 13 12.669 689.82861 TOL 14 14.788 8378.59375 nC8 15 18.534 7974.54883 nC9 16 21.938 7276.47705 nC10 17 25.063 6486.47998 nC11 18 27.970 5279.17187 nC12 19 30.690 4451.49902 nC13 20 33.254 4156.73389 nC14 21 35.672 3345.80273 nC15 22 37.959 3219.63745 nC16 23 40.137 2708.28003 nC17 24 40.227 219.38252 Pr 25 42.203 2413.01929 nC18 26 42.455 317.17825 Ph 27 44.173 2206.65405 nC19 28 46.056 1646.56616 nC20 29 47.858 1504.49097 nC21 30 49.579 1069.23608 nC22 31 51.234 949.49316 nC23 32 52.823 719.34735 nC24 33 54.355 627.46436 nC25 34 55.829 483.81885 nC26 35 57.253 407.86371 nC27 36 58.628 358.52216 nC28 37 59.956 341.01791 nC29 38 61.245 214.87863 nC30 39 62.647 146.06461 nC31 40 64.259 127.66831 nC32 41 66.155 85.17574 nC33 42 68.403 64.29253 nC34 43 71.066 56.55088 nC35 44 74.282 28.61854 nC36 45 78.140 220.95929 nC37 46 83.075 26.95426 nC38 Totals: 9.84518e4

Example 4

Conducted in a manner similar to that of Example 2 on a core specimen from oil shale block CM-1B; however, in this example the applied effective stress was 1,000 psi. Results for the gas collected and analyzed by hydrocarbon gas sample gas chromatography (GC) and non-hydrocarbon gas sample gas chromatography (GC) (GC not shown) are shown in FIG. 26, Table 7 and Table 1. In FIG. 26 the y-axis 4030 represents the detector response in pico-amperes (pA) while the x-axis 4031 represents the retention time in minutes. In FIG. 26 peak 4032 represents the response for methane, peak 4033 represents the response for ethane, peak 4034 represents the response for propane, peak 4035 represents the response for butane, peak 4036 represents the response for pentane and peak 4037 represents the response for hexane. Results for the liquid collected and analyzed by whole oil gas chromatography (WOGC) are shown in FIG. 27, Table 8 and Table 1. In FIG. 27 the y-axis 6000 represents the detector response in pico-amperes (pA) while the x-axis 6001 represents the retention time in minutes. The GC chromatogram is shown generally by label 6002 with individual identified peaks labeled with abbreviations.

TABLE 7 Peak and Area Details for FIG. 26 - Example 4 - 1000 psi stress - Gas GC Peak Ret. Time Area Compound Number [min] [pA * s] Name 1 0.910 1.43817e4 Methane 2 1.000 301.69287 ? 3 1.078 1.37821e4 Ethane 4 2.541 1.64047e4 Propane 5 4.249 2286.08032 iC4 6 4.924 992.04395 ? 7 5.030 6167.50000 n-Butane 8 5.303 534.37000 ? 9 5.583 358.96567 ? 10 6.131 27.44937 ? 11 6.376 1174.68872 iC5 12 6.740 223.61662 ? 13 6.902 2340.79248 n-Pentane 14 7.071 5.29245 ? 15 7.136 309.94775 ? 16 7.295 154.59171 ? 17 7.381 169.53279 ? 18 7.555 2.80458 ? 19 7.601 5.22327 ? 20 7.751 117.69164 ? 21 8.134 29.41086 ? 22 8.219 19.39338 ? 23 8.342 133.52739 ? 24 8.492 281.61343 2-methyl pentane 25 8.647 22.19704 ? 26 8.882 99.56919 ? 27 9.190 86.65676 ? 28 9.443 657.28754 n-Hexane 29 9.552 4.12572 ? 30 9.646 34.33701 ? 31 9.710 59.12064 ? 32 9.788 62.97972 ? 33 9.847 15.13559 ? 34 9.909 6.88310 ? 35 10.009 29.11555 ? 36 10.223 23.65434 ? 37 10.298 173.95422 ? 38 10.416 3.37255 ? 39 10.569 7.64592 ? 40 11.246 47.30062 ? 41 11.485 32.04262 ? 42 11.560 13.74583 ? 43 11.702 2.68917 ? 44 11.815 36.51670 ? 45 11.941 6.45255 ? 46 12.103 28.44484 ? 47 12.172 5.96475 ? 48 12.304 17.59856 ? 49 12.399 15.17446 ? 50 12.490 31.96492 ? 51 12.584 3.27834 ? 52 12.675 14.08259 ? 53 12.934 207.21574 ? 54 13.105 8.29743 ? 55 13.151 2.25476 ? 56 13.201 8.36965 ? 57 13.312 9.49917 ? 58 13.436 6.09893 ? 59 13.521 46.34579 ? 60 13.900 20.53506 ? 61 14.090 8.41120 ? 62 14.318 4.36870 ? 63 14.550 8.68951 ? 64 14.610 4.39150 ? 65 14.727 4.35713 ? 66 14.870 37.17881 ? 67 14.951 5.78219 ? 68 15.080 5.54470 ? 69 15.136 8.07308 ? 70 15.336 2.07075 ? 71 15.425 2.67118 ? 72 15.516 8.47004 ? 73 15.569 3.89987 ? 74 15.641 3.96979 ? 75 15.776 40.75155 ? 76 16.558 5.06379 ? 77 16.641 8.43767 ? 78 17.437 6.00180 ? 79 18.095 7.66881 ? 80 15.853 3.97375 ? 81 16.016 5.68997 ? 82 16.482 3.27234 ?

TABLE 8 Peak and Area Details from FIG. 27 - Example 4 - 1000 psi stress - Liquid GC. Peak Ret. Time Peak Area Compound Number [min] [pA * s] Name  1 2.737 117.78948 iC4  2 2.901 923.40125 nC4  3 3.528 1079.83325 iC5  4 3.891 3341.44604 nC5  5 5.493 1364.53186 2MP  6 5.930 533.68530 3MP  7 6.552 5160.12207 nC6  8 7.452 1770.29932 MCP  9 8.717 487.04718 BZ 10 9.206 712.61566 CH 11 10.634 7302.51123 nC7 12 11. 1755.92236 MCH 13 12.760 2145.57666 TOL 14 14.755 6434.40430 nC8 15 18.503 6007.12891 nC9 16 21.906 5417.67480 nC10 17 25.030 4565.11084 nC11 18 27.936 3773.91943 nC12 19 30.656 3112.23950 nC13 20 33.220 2998.37720 nC14 21 35.639 2304.97632 nC15 22 37.927 2197.88892 nC16 23 40.102 1791.11877 nC17 24 40.257 278.39423 Pr 25 42.171 1589.64233 nC18 26 42.428 241.65131 Ph 27 44.141 1442.51843 nC19 28 46.025 1031.68481 nC20 29 47.825 957.65479 nC21 30 49.551 609.59943 nC22 31 51.208 526.53339 nC23 32 52.798 383.01022 nC24 33 54.329 325.93640 nC25 34 55.806 248.12935 nC26 35 57.230 203.21725 nC27 36 58.603 168.78055 nC28 37 59.934 140.40034 nC29 38 61.222 95.47594 nC30 39 62.622 77.49546 nC31 40 64.234 49.08135 nC32 41 66.114 33.61663 nC33 42 68.350 27.46170 nC34 43 71.030 35.89277 nC35 44 74.162 16.87499 nC36 45 78.055 29.21477 nC37 46 82.653 9.88631 nC38 Totals: 7.38198e4

Example 5

Conducted in a manner similar to that of Example 2 on a core specimen from oil shale block CM-1B; however, in this example the applied effective stress was 1,000 psi. Results for the gas collected and analyzed by hydrocarbon gas sample gas chromatography (GC) and non-hydrocarbon gas sample gas chromatography (GC) (GC not shown) are shown in FIG. 28, Table 9 and Table 1. In FIG. 28 the y-axis 4040 represents the detector response in pico-amperes (pA) while the x-axis 4041 represents the retention time in minutes. In FIG. 28 peak 4042 represents the response for methane, peak 4043 represents the response for ethane, peak 4044 represents the response for propane, peak 4045 represents the response for butane, peak 4046 represents the response for pentane and peak 4047 represents the response for hexane.

TABLE 9 Peak and Area Details for FIG. 28 - Example 5 - 1000 psi stress - Gas GC Peak Ret. Time Area Compound Number [min] [pA * s] Name 1 0.910 1.59035e4 Methane 2 0.999 434.21375 ? 3 1.077 1.53391e4 Ethane 4 2.537 1.86530e4 Propane 5 4.235 2545.45850 iC4 6 4.907 1192.68970 ? 7 5.015 6814.44678 n-Butane 8 5.285 687.83679 ? 9 5.564 463.25885 ? 10 6.106 30.02624 ? 11 6.351 1295.13477 iC5 12 6.712 245.26985 ? 13 6.876 2561.11792 n-Pentane 14 7.039 4.50998 ? 15 7.109 408.32999 ? 16 7.268 204.45311 ? 17 7.354 207.92183 ? 18 7.527 4.02397 ? 19 7.574 5.65699 ? 20 7.755 2.35952 ? 21 7.818 2.00382 ? 22 8.107 38.23093 ? 23 8.193 20.54333 ? 24 8.317 148.54445 ? 25 8.468 300.31586 2-methyl pentane 26 8.622 26.06131 ? 27 8.858 113.70123 ? 28 9.168 90.37163 ? 29 9.422 694.74438 n-Hexane 30 9.531 4.88323 ? 31 9.625 45.91505 ? 32 9.689 76.32931 ? 33 9.767 77.63214 ? 34 9.826 19.23768 ? 35 9.889 8.54605 ? 36 9.989 37.74959 ? 37 10.204 30.83943 ? 38 10.280 184.58420 ? 39 10.397 4.43609 ? 40 10.551 10.59880 ? 41 10.843 2.30370 ? 42 11.231 55.64666 ? 43 11.472 35.46931 ? 44 11.547 17.16440 ? 45 11.691 3.30460 ? 46 11.804 39.46368 ? 47 11.931 7.32969 ? 48 12.094 30.59748 ? 49 12.163 6.93754 ? 50 12.295 18.69523 ? 51 12.391 15.96837 ? 52 12.482 33.66422 ? 53 12.577 2.02121 ? 54 12.618 2.32440 ? 55 12.670 12.83803 ? 56 12.851 2.22731 ? 57 12.929 218.23195 ? 58 13.100 14.33166 ? 59 13.198 10.20244 ? 60 13.310 12.02551 ? 61 13.432 8.23884 ? 62 13.519 47.64641 ? 63 13.898 22.63760 ? 64 14.090 9.29738 ? 65 14.319 3.88012 ? 66 14.551 9.26884 ? 67 14.612 4.34914 ? 68 14.729 4.07543 ? 69 14.872 46.24465 ? 70 14.954 6.62461 ? 71 15.084 3.92423 ? 72 15.139 8.60328 ? 73 15.340 2.17899 ? 74 15.430 2.96646 ? 75 15.521 9.66407 ? 76 15.578 4.27190 ? 77 15.645 4.37904 ? 78 15.703 2.68909 ? 79 15.782 46.97895 ? 80 15.859 4.69475 ? 81 16.022 7.36509 ? 82 16.489 3.91073 ? 83 16.564 6.22445 ? 84 16.648 10.24660 ? 85 17.269 2.69753 ? 86 17.445 10.16989 ? 87 17.925 2.28341 ? 88 17.979 2.71101 ? 89 18.104 11.19730 ?

TABLE 1 Summary data for Examples 1-5 Example 1 Example 2 Example 3 Example 4 Example 5 Effective Stress (psi) 0 400 400 1000 1000 Sample weight (g) 82.46 42.57 48.34 43.61 43.73 Sample weight loss (g) 19.21 10.29 11.41 10.20 9.17 Fluids Recovered: Oil (g) 10.91 3.63 3.77 3.02 2.10 36.2 gal/ton 23.4 gal/ton 21.0 gal/ton 19.3 gal/ton 13/1 gal/ton Water (g) 0.90 0.30 0.34 0.39 0.28 2.6 gal/ton 1.7 gal/ton 1.7 gal/ton 2.1 gal/ton 1.5 gal/ton HC gas (g) 2.09 1.33 1.58 1.53 1.66 683 scf/ton 811 scf/ton 862 scf/ton 905 scf/ton 974 scf/ton CO₂ (g) 3.35 1.70 1.64 1.74 1.71 700 scf/ton 690 scf/ton 586 scf/ton 690 scf/ton 673 scf/ton H₂S (g) 0.06 0.0 0.0 0.0 0.0 Coke Recovered: 0.0 0.73 0.79 .47 0.53 Inferred Oil (g) 0.0 1.67 1.81 1.07 1.21 0 gal/ton 10.8 gal/ton 10.0 gal/ton 6.8 gal/ton 7.6 gal/ton Total Oil (g) 10.91 5.31 5.58 4.09 3.30 36.2 gal/ton 34.1 gal/ton 31.0 gal/ton 26.1 gal/ton 20.7 gal/ton Balance (g) 1.91 2.59 3.29 3.05 2.91 Analysis

The gas and liquid samples obtained through the experimental procedures and gas and liquid sample collection procedures described for Examples 1-5, were analyzed by the following hydrocarbon gas sample gas chromatography (GC) analysis methodology, non-hydrocarbon gas sample gas chromatography (GC) analysis methodology, gas sample GC peak identification and integration methodology, whole oil gas chromatography (WOGC) analysis methodology, and whole oil gas chromatography (WOGC) peak identification and integration methodology.

Gas samples collected during the heating tests as described in Examples 1-5 were analyzed for both hydrocarbon and non-hydrocarbon gases, using an Agilent Model 6890 Gas Chromatograph coupled to an Agilent Model 5973 quadrapole mass selective detector. The 6890 GC was configured with two inlets (front and back) and two detectors (front and back) with two fixed volume sample loops for sample introduction. Peak identifications and integrations were performed using the Chemstation software (Revision A.03.01) supplied with the GC instrument. For hydrocarbon gases, the GC configuration consisted of the following:

-   -   a) split/splitless inlet (back position of the GC)     -   b) FID (Flame ionization detector) back position of the GC     -   c) HP Ultra-2 (5% Phenyl Methyl Siloxane) capillary columns         (two) (25 meters×200 μm ID) one directed to the FID detector,         the other to an Agilent 5973 Mass Selective Detector     -   d) 500 μl fixed volume sample loop     -   e) six-port gas sampling valve     -   f) cryogenic (liquid nitrogen) oven cooling capability     -   g) Oven program −80° C. for 2 mins., 20° C./min. to 0° C., then         4° C./min to 20° C., then 10° C./min. to 100° C., hold for 1         min.     -   h) Helium carrier gas flow rate of 2.2 ml/min.     -   i) Inlet temperature 100° C.     -   j) Inlet pressure 19.35 psi     -   k) Split ratio 25:1     -   l) FID temperature 310° C.

For non-hydrocarbon gases (e.g., argon, carbon dioxide and hydrogen sulfide) the GC configuration consisted of the following:

-   -   a) PTV (programmable temperature vaporization) inlet (front         position of the GC)     -   b) TCD (Thermal conductivity detector) front position of the GC     -   c) GS-GasPro capillary column (30 meters×0.32 mm ID)     -   d) 100 μl fixed volume sample loop     -   e) six port gas sampling valve     -   f) Oven program: 25° C. hold for 2 min., then 10° C./min to 200°         C., hold 1 min.     -   g) Helium carrier gas flow rate of 4.1 ml/min.     -   h) Inlet temperature 200° C.     -   i) Inlet pressure 14.9 psi     -   j) Splitless mode     -   k) TCD temperature 250° C.

For Examples 1-5, a stainless steel sample cylinder containing gas collected from the Parr vessel (FIG. 18) was fitted with a two stage gas regulator (designed for lecture bottle use) to reduce gas pressure to approximately twenty pounds per square inch. A septum fitting was positioned at the outlet port of the regulator to allow withdrawal of gas by means of a Hamilton model 1005 gas-tight syringe. Both the septum fitting and the syringe were purged with gas from the stainless steel sample cylinder to ensure that a representative gas sample was collected. The gas sample was then transferred to a stainless steel cell (septum cell) equipped with a pressure transducer and a septum fitting. The septum cell was connected to the fixed volume sample loop mounted on the GC by stainless steel capillary tubing. The septum cell and sample loop were evacuated for approximately 5 minutes. The evacuated septum cell was then isolated from the evacuated sample loop by closure of a needle valve positioned at the outlet of the septum cell. The gas sample was introduced into the septum cell from the gas-tight syringe through the septum fitting and a pressure recorded. The evacuated sample loop was then opened to the pressurized septum cell and the gas sample allowed to equilibrate between the sample loop and the septum cell for one minute. The equilibrium pressure was then recorded, to allow calculation of the total moles of gas present in the sample loop before injection into the GC inlet. The sample loop contents were then swept into the inlet by Helium carrier gas and components separated by retention time in the capillary column, based upon the GC oven temperature program and carrier gas flow rates.

Calibration curves, correlating integrated peak areas with concentration, were generated for quantification of gas compositions using certified gas standards. For hydrocarbon gases, standards containing a mixture of methane, ethane, propane, butane, pentane and hexane in a helium matrix in varying concentrations (parts per million, mole basis) were injected into the GC through the fixed volume sample loop at atmospheric pressure. For non-hydrocarbon gases, standards containing individual components, i.e., carbon dioxide in helium and hydrogen sulfide in natural gas, were injected into the GC at varying pressures in the sample loop to generate calibration curves.

The hydrocarbon gas sample molar percentages reported in FIG. 16 were obtained using the following procedure. Gas standards for methane, ethane, propane, butane, pentane and hexane of at least three varying concentrations were run on the gas chromatograph to obtain peak area responses for such standard concentrations. The known concentrations were then correlated to the respective peak area responses within the Chemstation software to generate calibration curves for methane, ethane, propane, butane, pentane and hexane. The calibration curves were plotted in Chemstation to ensure good linearity (R2>0.98) between concentration and peak intensity. A linear fit was used for each calibrated compound, so that the response factor between peak area and molar concentration was a function of the slope of the line as determined by the Chemstation software. The Chemstation software program then determined a response factor relating GC peak area intensity to the amount of moles for each calibrated compound. The software then determined the number of moles of each calibrated compound from the response factor and the peak area. The peak areas used in Examples 1-5 are reported in Tables 2, 4, 5, 7, and 9. The number of moles of each identified compound for which a calibration curve was not determined (i.e., iso-butane, iso-pentane, and 2-methyl pentane) was then estimated using the response factor for the closest calibrated compound (i.e., butane for iso-butane; pentane for iso-pentane; and hexane for 2-methyl pentane) multiplied by the ratio of the peak area for the identified compound for which a calibration curve was not determined to the peak area of the calibrated compound. The values reported in FIG. 16 were then taken as a percentage of the total of all identified hydrocarbon gas GC areas (i.e., methane, ethane, propane, iso-butane, n-butane, iso-pentane, n-pentane, 2-methyl pentane, and n-hexane) and calculated molar concentrations. Thus the graphed methane to normal C6 molar percentages for all of the experiments do not include the molar contribution of the unidentified hydrocarbon gas species listed in Tables 2, 4, 5, 7, or 9 (e.g., peak numbers 2, 6, 8-11, 13, 15-22, 24-26, and 28-78 in Table 2).

Liquid samples collected during the heating tests as described in Examples 1, 3 and 4 were analyzed by whole oil gas chromatography (WOGC) according to the following procedure. Samples, QA/QC standards and blanks (carbon disulfide) were analyzed using an Ultra 1 Methyl Siloxane column (25 m length, 0.32 μm diameter, 0.52 μm film thickness) in an Agilent 6890 GC equipped with a split/splitless injector, autosampler and flame ionization detector (FID). Samples were injected onto the capillary column in split mode with a split ratio of 80:1. The GC oven temperature was kept constant at 20° C. for 5 min, programmed from 20° C. to 300° C. at a rate of 5° C. min⁻¹, and then maintained at 300° C. for 30 min (total run time=90 min.). The injector temperature was maintained at 300° C. and the FID temperature set at 310° C. Helium was used as carrier gas at a flow of 2.1 mL min⁻¹. Peak identifications and integrations were performed using Chemstation software Rev.A.10.02[1757] (Agilent Tech. 1990-2003) supplied with the Agilent instrument.

Standard mixtures of hydrocarbons were analyzed in parallel by the WOGC method described above and by an Agilent 6890 GC equipped with a split/splitless injector, autosampler and mass selective detector (MS) under the same conditions. Identification of the hydrocarbon compounds was conducted by analysis of the mass spectrum of each peak from the GC-MS. Since conditions were identical for both instruments, peak identification conducted on the GC-MS could be transferred to the peaks obtained on the GC-FID. Using these data, a compound table relating retention time and peak identification was set up in the GC-FID Chemstation. This table was used for peak identification.

The gas chromatograms obtained on the liquid samples (FIGS. 4, 9 and 11) were analyzed using a pseudo-component technique. The convention used for identifying each pseudo-component was to integrate all contributions from normal alkane to next occurring normal alkane with the pseudo-component being named by the late eluting n-alkane. For example, the C-10 pseudo-component would be obtained from integration beginning just past normal-C9 and continue just through normal-C10. The carbon number weight % and mole % values for the pseudo-components obtained in this manner were assigned using correlations developed by Katz and Firoozabadi (Katz, D. L., and A. Firoozabadi, 1978. Predicting phase behavior of condensate/crude-oil systems using methane interaction coefficients, J. Petroleum Technology (November 1978), 1649-1655). Results of the pseudo-component analyses for Examples 1, 3 and 4 are shown in Tables 10, 11 and 12.

An exemplary pseudo component weight percent calculation is presented below with reference to Table 10 for the C10 pseudo component for Example 1 in order to illustrate the technique. First, the C-10 pseudo-component total area is obtained from integration of the area beginning just past normal-C9 and continued just through normal-C10 as described above. The total integration area for the C10 pseudo component is 10551.700 pico-ampere-seconds (pAs). The total C10 pseudo component integration area (10551.700 pAs) is then multiplied by the C10 pseudo component density (0.7780 g/ml) to yield an “area×density” of 8209.22 pAs g/ml. Similarly, the peak integration areas for each pseudo component and all lighter listed compounds (i.e., nC3, iC4, nC4, iC5 & nC5) are determined and multiplied by their respective densities to yield “area×density” numbers for each respective pseudo component and listed compound. The respective determined “area×density” numbers for each pseudo component and listed compound is then summed to determine a “total area×density” number. The “total area×density” number for Example 1 is 96266.96 pAs g/ml. The C10 pseudo component weight percentage is then obtained by dividing the C10 pseudo component “area×density” number (8209.22 pAs g/ml) by the “total area×density” number (96266.96 pAs g/ml) to obtain the C10 pseudo component weight percentage of 8.53 weight percent.

An exemplary pseudo component molar percent calculation is presented below with reference to Table 10 for the C10 pseudo component for Example 1 in order to further illustrate the pseudo component technique. First, the C-10 pseudo-component total area is obtained from integration of the area beginning just past normal-C9 and continued just through normal-C10 as described above. The total integration area for the C10 pseudo component is 10551.700 pico-ampere-seconds (pAs). The total C10 pseudo component integration area (10551.700 pAs) is then multiplied by the C10 pseudo component density (0.7780 g/ml) to yield an “area×density” of 8209.22 pAs g/ml. Similarly, the integration areas for each pseudo component and all lighter listed compounds (i.e., nC3, iC4, nC4, iC5 & nC5) are determined and multiplied by their respective densities to yield “area×density” numbers for each respective pseudo component and listed compound. The C10 pseudo component “area×density” number (8209.22 pAs g/ml) is then divided by the C10 pseudo component molecular weight (134.00 g/mol) to yield a C10 pseudo component “area×density/molecular weight” number of 61.26 pAs mol/ml. Similarly, the “area×density” number for each pseudo component and listed compound is then divided by such components or compounds respective molecular weight to yield an “area×density/molecular weight” number for each respective pseudo component and listed compound. The respective determined “area×density/molecular weight” numbers for each pseudo component and listed compound is then summed to determine a “total area×density/molecular weight” number. The total “total area×density/molecular weight” number for Example 1 is 665.28 pAs mol/ml. The C10 pseudo component molar percentage is then obtained by dividing the C10 pseudo component “area×density/molecular weight” number (61.26 pAs mol/ml) by the “total area×density/molecular weight” number (665.28 pAs mol/ml) to obtain the C10 pseudo component molar percentage of 9.21 molar percent.

TABLE 10 Pseudo-Components for Example 1 - GC of Liquid - 0 Stress Avg. Boiling Density Molecular Component Area (cts.) Area % Pt. (° F.) (g/ml) Wt. (g/mol) Wt. % Mol % nC₃ 41.881 0.03 −43.73 0.5069 44.10 0.02 0.07 iC₄ 120.873 0.10 10.94 0.5628 58.12 0.07 0.18 nC₄ 805.690 0.66 31.10 0.5840 58.12 0.49 1.22 iC₅ 1092.699 0.89 82.13 0.6244 72.15 0.71 1.42 nC₅ 2801.815 2.29 96.93 0.6311 72.15 1.84 3.68 Pseudo C₆ 7150.533 5.84 147.00 0.6850 84.00 5.09 8.76 Pseudo C₇ 10372.800 8.47 197.50 0.7220 96.00 7.78 11.73 Pseudo C₈ 11703.500 9.56 242.00 0.7450 107.00 9.06 12.25 Pseudo C₉ 11776.200 9.61 288.00 0.7640 121.00 9.35 11.18 Pseudo C₁₀ 10551.700 8.61 330.50 0.7780 134.00 8.53 9.21 Pseudo C₁₁ 9274.333 7.57 369.00 0.7890 147.00 7.60 7.48 Pseudo C₁₂ 8709.231 7.11 407.00 0.8000 161.00 7.24 6.50 Pseudo C₁₃ 7494.549 6.12 441.00 0.8110 175.00 6.31 5.22 Pseudo C₁₄ 6223.394 5.08 475.50 0.8220 190.00 5.31 4.05 Pseudo C₁₅ 6000.179 4.90 511.00 0.8320 206.00 5.19 3.64 Pseudo C₁₆ 5345.791 4.36 542.00 0.8390 222.00 4.66 3.04 Pseudo C₁₇ 4051.886 3.31 572.00 0.8470 237.00 3.57 2.18 Pseudo C₁₈ 3398.586 2.77 595.00 0.8520 251.00 3.01 1.73 Pseudo C₁₉ 2812.101 2.30 617.00 0.8570 263.00 2.50 1.38 Pseudo C₂₀ 2304.651 1.88 640.50 0.8620 275.00 2.06 1.09 Pseudo C₂₁ 2038.925 1.66 664.00 0.8670 291.00 1.84 0.91 Pseudo C₂₂ 1497.726 1.22 686.00 0.8720 305.00 1.36 0.64 Pseudo C₂₃ 1173.834 0.96 707.00 0.8770 318.00 1.07 0.49 Pseudo C₂₄ 822.762 0.67 727.00 0.8810 331.00 0.75 0.33 Pseudo C₂₅ 677.938 0.55 747.00 0.8850 345.00 0.62 0.26 Pseudo C₂₆ 532.788 0.43 766.00 0.8890 359.00 0.49 0.20 Pseudo C₂₇ 459.465 0.38 784.00 0.8930 374.00 0.43 0.16 Pseudo C₂₈ 413.397 0.34 802.00 0.8960 388.00 0.38 0.14 Pseudo C₂₉ 522.898 0.43 817.00 0.8990 402.00 0.49 0.18 Pseudo C₃₀ 336.968 0.28 834.00 0.9020 416.00 0.32 0.11 Pseudo C₃₁ 322.495 0.26 850.00 0.9060 430.00 0.30 0.10 Pseudo C₃₂ 175.615 0.14 866.00 0.9090 444.00 0.17 0.05 Pseudo C₃₃ 165.912 0.14 881.00 0.9120 458.00 0.16 0.05 Pseudo C₃₄ 341.051 0.28 895.00 0.9140 472.00 0.32 0.10 Pseudo C₃₅ 286.861 0.23 908.00 0.9170 486.00 0.27 0.08 Pseudo C₃₆ 152.814 0.12 922.00 0.9190 500.00 0.15 0.04 Pseudo C₃₇ 356.947 0.29 934.00 0.9220 514.00 0.34 0.10 Pseudo C₃₈ 173.428 0.14 947.00 0.9240 528.00 0.17 0.05 Totals 122484.217 100.00 100.00 100.00

TABLE 11 Pseudo-Components for Example 3 - GC of Liquid - 400 psi stress Avg. Boiling Density Molecular Wt. Component Area Area % Pt. (° F.) (g/ml) (g/mol) Wt. % Mol % nC₃ 35.845 0.014 −43.730 0.5069 44.10 0.01 0.03 iC₄ 103.065 0.041 10.940 0.5628 58.12 0.03 0.07 nC₄ 821.863 0.328 31.100 0.5840 58.12 0.24 0.62 iC₅ 1187.912 0.474 82.130 0.6244 72.15 0.37 0.77 nC₅ 3752.655 1.498 96.930 0.6311 72.15 1.20 2.45 Pseudo C₆ 12040.900 4.805 147.000 0.6850 84.00 4.17 7.34 Pseudo C₇ 20038.600 7.997 197.500 0.7220 96.00 7.31 11.26 Pseudo C₈ 24531.500 9.790 242.000 0.7450 107.00 9.23 12.76 Pseudo C₉ 25315.000 10.103 288.000 0.7640 121.00 9.77 11.94 Pseudo C₁₀ 22640.400 9.035 330.500 0.7780 134.00 8.90 9.82 Pseudo C₁₁ 20268.100 8.089 369.000 0.7890 147.00 8.08 8.13 Pseudo C₁₂ 18675.600 7.453 407.000 0.8000 161.00 7.55 6.93 Pseudo C₁₃ 16591.100 6.621 441.000 0.8110 175.00 6.80 5.74 Pseudo C₁₄ 13654.000 5.449 475.500 0.8220 190.00 5.67 4.41 Pseudo C₁₅ 13006.300 5.191 511.000 0.8320 206.00 5.47 3.92 Pseudo C₁₆ 11962.200 4.774 542.000 0.8390 222.00 5.07 3.38 Pseudo C₁₇ 8851.622 3.533 572.000 0.8470 237.00 3.79 2.36 Pseudo C₁₈ 7251.438 2.894 595.000 0.8520 251.00 3.12 1.84 Pseudo C₁₉ 5946.166 2.373 617.000 0.8570 263.00 2.57 1.45 Pseudo C₂₀ 4645.178 1.854 640.500 0.8620 275.00 2.02 1.09 Pseudo C₂₁ 4188.168 1.671 664.000 0.8670 291.00 1.83 0.93 Pseudo C₂₂ 2868.636 1.145 686.000 0.8720 305.00 1.26 0.61 Pseudo C₂₃ 2188.895 0.874 707.000 0.8770 318.00 0.97 0.45 Pseudo C₂₄ 1466.162 0.585 727.000 0.8810 331.00 0.65 0.29 Pseudo C₂₅ 1181.133 0.471 747.000 0.8850 345.00 0.53 0.23 Pseudo C₂₆ 875.812 0.350 766.000 0.8890 359.00 0.39 0.16 Pseudo C₂₇ 617.103 0.246 784.000 0.8930 374.00 0.28 0.11 Pseudo C₂₈ 538.147 0.215 802.000 0.8960 388.00 0.24 0.09 Pseudo C₂₉ 659.027 0.263 817.000 0.8990 402.00 0.30 0.11 Pseudo C₃₀ 1013.942 0.405 834.000 0.9020 416.00 0.46 0.16 Pseudo C₃₁ 761.259 0.304 850.000 0.9060 430.00 0.35 0.12 Pseudo C₃₂ 416.031 0.166 866.000 0.9090 444.00 0.19 0.06 Pseudo C₃₃ 231.207 0.092 881.000 0.9120 458.00 0.11 0.03 Pseudo C₃₄ 566.926 0.226 895.000 0.9140 472.00 0.26 0.08 Pseudo C₃₅ 426.697 0.170 908.000 0.9170 486.00 0.20 0.06 Pseudo C₃₆ 191.626 0.076 922.000 0.9190 500.00 0.09 0.03 Pseudo C₃₇ 778.713 0.311 934.000 0.9220 514.00 0.36 0.10 Pseudo C₃₈ 285.217 0.114 947.000 0.9240 528.00 0.13 0.04 Totals 250574.144 100.000 100.00 100.00

TABLE 12 Pseudo-Components for Example 4 - GC of Liquid - 1000 psi stress Avg. Boiling Density Molecular Wt. Component Area Area % Pt. (° F.) (g/ml) (g/mol) Wt. % Mol % nC₃ 44.761 0.023 −43.730 0.5069 44.10 0.01 0.05 iC₄ 117.876 0.060 10.940 0.5628 58.12 0.04 0.11 nC₄ 927.866 0.472 31.100 0.5840 58.12 0.35 0.87 iC₅ 1082.570 0.550 82.130 0.6244 72.15 0.44 0.88 nC₅ 3346.533 1.701 96.930 0.6311 72.15 1.37 2.74 Pseudo C₆ 9579.443 4.870 147.000 0.6850 84.00 4.24 7.31 Pseudo C₇ 16046.200 8.158 197.500 0.7220 96.00 7.49 11.29 Pseudo C₈ 19693.300 10.012 242.000 0.7450 107.00 9.48 12.83 Pseudo C₉ 20326.300 10.334 288.000 0.7640 121.00 10.04 12.01 Pseudo C₁₀ 18297.600 9.302 330.500 0.7780 134.00 9.20 9.94 Pseudo C₁₁ 16385.600 8.330 369.000 0.7890 147.00 8.36 8.23 Pseudo C₁₂ 15349.000 7.803 407.000 0.8000 161.00 7.94 7.14 Pseudo C₁₃ 13116.500 6.668 441.000 0.8110 175.00 6.88 5.69 Pseudo C₁₄ 10816.100 5.499 475.500 0.8220 190.00 5.75 4.38 Pseudo C₁₅ 10276.900 5.225 511.000 0.8320 206.00 5.53 3.88 Pseudo C₁₆ 9537.818 4.849 542.000 0.8390 222.00 5.17 3.37 Pseudo C₁₇ 6930.611 3.523 572.000 0.8470 237.00 3.79 2.32 Pseudo C₁₈ 5549.802 2.821 595.000 0.8520 251.00 3.06 1.76 Pseudo C₁₉ 4440.457 2.257 617.000 0.8570 263.00 2.46 1.35 Pseudo C₂₀ 3451.250 1.755 640.500 0.8620 275.00 1.92 1.01 Pseudo C₂₁ 3133.251 1.593 664.000 0.8670 291.00 1.76 0.87 Pseudo C₂₂ 2088.036 1.062 686.000 0.8720 305.00 1.18 0.56 Pseudo C₂₃ 1519.460 0.772 707.000 0.8770 318.00 0.86 0.39 Pseudo C₂₄ 907.473 0.461 727.000 0.8810 331.00 0.52 0.23 Pseudo C₂₅ 683.205 0.347 747.000 0.8850 345.00 0.39 0.16 Pseudo C₂₆ 493.413 0.251 766.000 0.8890 359.00 0.28 0.11 Pseudo C₂₇ 326.831 0.166 784.000 0.8930 374.00 0.19 0.07 Pseudo C₂₈ 272.527 0.139 802.000 0.8960 388.00 0.16 0.06 Pseudo C₂₉ 291.862 0.148 817.000 0.8990 402.00 0.17 0.06 Pseudo C₃₀ 462.840 0.235 834.000 0.9020 416.00 0.27 0.09 Pseudo C₃₁ 352.886 0.179 850.000 0.9060 430.00 0.21 0.07 Pseudo C₃₂ 168.635 0.086 866.000 0.9090 444.00 0.10 0.03 Pseudo C₃₃ 67.575 0.034 881.000 0.9120 458.00 0.04 0.01 Pseudo C₃₄ 95.207 0.048 895.000 0.9140 472.00 0.06 0.02 Pseudo C₃₅ 226.660 0.115 908.000 0.9170 486.00 0.13 0.04 Pseudo C₃₆ 169.729 0.086 922.000 0.9190 500.00 0.10 0.03 Pseudo C₃₇ 80.976 0.041 934.000 0.9220 514.00 0.05 0.01 Pseudo C₃₈ 42.940 0.022 947.000 0.9240 528.00 0.03 0.01 Totals 196699.994 100.000 100.00 100.00

TOC and Rock-eval tests were performed on specimens from oil shale block CM-1B taken at the same stratigraphic interval as the specimens tested by the Parr heating method described in Examples 1-5. These tests resulted in a TOC of 21% and a Rock-eval Hydrogen Index of 872 mg/g-toc.

The TOC and rock-eval procedures described below were performed on the oil shale specimens remaining after the Parr heating tests described in Examples 1-5. Results are shown in Table 13.

The Rock-Eval pyrolysis analyses described above were performed using the following procedures. Rock-Eval pyrolysis analyses were performed on calibration rock standards (IFP standard #55000), blanks, and samples using a Delsi Rock-Eval II instrument. Rock samples were crushed, micronized, and air-dried before loading into Rock-Eval crucibles. Between 25 and 100 mg of powdered-rock samples were loaded into the crucibles depending on the total organic carbon (TOC) content of the sample. Two or three blanks were run at the beginning of each day to purge the system and stabilize the temperature. Two or three samples of IFP calibration standard #55000 with weight of 100+/−1 mg were run to calibrate the system. If the Rock-Eval T_(max) parameter was 419° C.+/−2° C. on these standards, analyses proceeded with samples. The standard was also run before and after every 10 samples to monitor the instrument's performance.

The Rock-Eval pyrolysis technique involves the rate-programmed heating of a powdered rock sample to a high temperature in an inert (helium) atmosphere and the characterization of products generated from the thermal breakdown of chemical bonds. After introduction of the sample the pyrolysis oven was held isothermally at 300° C. for three minutes. Hydrocarbons generated during this stage are detected by a flame-ionization detector (FID) yielding the S₁ peak. The pyrolysis-oven temperature was then increased at a gradient of 25° C./minute up to 550° C., where the oven was held isothermally for one minute. Hydrocarbons generated during this step were detected by the FID and yielded the S₂ peak.

Hydrogen Index (HI) is calculated by normalizing the S₂ peak (expressed as mg_(hydrocarbons)/g_(rock)) to weight % TOC (Total Organic Carbon determined independently) as follows: HI=(S ₂/TOC)*100 where HI is expressed as mg_(hydrocarbons)/g_(TOC)

Total Organic Carbon (TOC) was determined by well known methods suitable for geological samples—i.e., any carbonate rock present was removed by acid treatment followed by combustion of the remaining material to produce and measure organic based carbon in the form of CO₂.

TABLE 13 TOC and Rock-eval Results on Oil Shale Specimens after the Parr Heating Tests. Example 1 Example 2 Example 3 Example 4 Example 5 TOC (%) 12.07 10.83 10.62 11.22 11.63 HI 77 83 81 62 77 (mg/g-toc)

The API gravity of Examples 1-5 was estimated by estimating the room temperature specific gravity (SG) of the liquids collected and the results are reported in Table 14. The API gravity was estimated from the determined specific gravity by applying the following formula: API gravity=(141.5/SG)−131.5

The specific gravity of each liquid sample was estimated using the following procedure. An empty 50 μl Hamilton Model 1705 gastight syringe was weighed on a Mettler AE 163 digital balance to determine the empty syringe weight. The syringe was then loaded by filling the syringe with a volume of liquid. The volume of liquid in the syringe was noted. The loaded syringe was then weighed. The liquid sample weight was then estimated by subtracting the loaded syringe measured weight from the measured empty syringe weight. The specific gravity was then estimated by dividing the liquid sample weight by the syringe volume occupied by the liquid sample.

TABLE 14 Estimated API Gravity of Liquid Samples from Examples 1-5 Example Example 1 Example 2 Example 3 Example 4 Example 5 API Gravity 29.92 30.00 27.13 32.70 30.00

The above-described processes may be of merit in connection with the recovery of hydrocarbons in the Piceance Basin of Colorado. Some have estimated that in some oil shale deposits of the Western United States, up to 1 million barrels of oil may be recoverable per surface acre. One study has estimated the oil shale resource within the nahcolite-bearing portions of the oil shale formations of the Piceance Basin to be 400 billion barrels of shale oil in place. Overall, up to 1 trillion barrels of shale oil may exist in the Piceance Basin alone.

Certain features of the present invention are described in terms of a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges formed by any combination of these limits are within the scope of the invention unless otherwise indicated. Although some of the dependent claims have single dependencies in accordance with U.S. practice, each of the features in any of such dependent claims can be combined with each of the features of one or more of the other dependent claims dependent upon the same independent claim or claims.

While it will be apparent that the invention herein described is well calculated to achieve the benefits and advantages set forth above, it will be appreciated that the invention is susceptible to modification, variation and change without departing from the spirit thereof. 

What is claimed is:
 1. A method for in situ heating of a selected portion of an organic-rich rock formation, comprising: providing casing in a wellbore located at least partially within the organic-rich rock formation, the casing extending to a depth within or below the selected portion of the organic-rich rock formation; providing a tubing within the casing, the tubing defining a first annulus between the tubing and the surrounding casing; injecting an oxidant and a combustible fuel into the wellbore, with either the oxidant or the combustible fuel being injected at an excess mass flow rate greater than about 2.0 times a stoichiometric combustion flow rate, wherein the excess mass flow rate is selected to provide a more uniform temperature profile in the first annulus along the selected portion of the organic rich rock formation; providing hardware in the wellbore so as to cause the oxidant and the combustible fuel to mix and to combust into flue gas at a first combustion depth located substantially within the selected portion of the organic-rich rock formation; moving the flue gas up the first annulus; and providing insulation along at least a portion of the tubing located below the first combustion depth, thereby reducing the heat transfer coefficient between the flue gas in the first annulus and the flue gas within the tubing.
 2. The method of claim 1, wherein the organic-rich rock formation contains heavy hydrocarbons.
 3. The method of claim 1, wherein the organic-rich rock formation is an oil shale formation.
 4. The method of claim 3, wherein the casing isolates fluid flow from at least a portion of the organic-rich rock formation into the wellbore.
 5. The method of claim 3, wherein the insulation has a selected length to further provide a more uniform temperature profile within the first annulus along the selected portion of the organic-rich rock formation.
 6. The method of claim 5, wherein the temperature along the selected portion of the organic-rich rock formation is between about 300° C. and 900° C.
 7. The method of claim 5, wherein the temperature along the selected portion of the organic-rich rock formation is between 300° C. and 750° C.
 8. The method of claim 5, wherein the insulation on the tubing is placed on an outer diameter of the tubing.
 9. The method of claim 3, wherein the insulation on the tubing comprises a first layer on an outer diameter of the tubing that extends from about the first combustion depth to proximate the bottom of the wellbore, and a second layer on an inner diameter of the tubing that extends from about the first combustion depth to about 20 meters below the first combustion depth.
 10. The method of claim 3, wherein the hardware comprises: a first tubular member residing within the tubing and extending to the selected portion of the organic-rich rock formation, the first tubular member defining a second annulus between the first tubular member and the surrounding tubing; and a first burner located at about the first combustion depth.
 11. The method of claim 10, where the combustible fuel is injected into the tubing and the oxidant is injected into the second annulus.
 12. The method of claim 10, where the oxidant is injected into the tubing and the combustible fuel is injected into the second annulus.
 13. The method of claim 10, wherein the hardware further comprises: a first tubular cowl disposed immediately below the first burner.
 14. The method of claim 13, wherein the first tubular cowl is fabricated from ceramic or a refractory metal.
 15. The method of claim 10, wherein the hardware further comprises: a second burner at a second combustion depth within the selected portion of the organic-rich rock formation, wherein the second combustion depth is lower than the first combustion depth; and a second tubular cowl disposed immediately below the second burner.
 16. The method of claim 15, wherein the step of providing insulation comprises providing insulation along at least a portion of the tubing located below the first combustion depth and below the second burner.
 17. The method of claim 16, wherein the insulation is placed along an outer diameter of the tubing.
 18. The method of claim 16, wherein the tubing adjacent the first burner and the second burner is fabricated from a highly heat-resistant material.
 19. The method of claim 16, wherein additional insulation is placed along an inner diameter of the tubing proximate the first burner and the second burner.
 20. The method of claim 19, wherein the additional insulation comprises ceramic.
 21. The method of claim 15, wherein the first burner and the second burner each supplies about 0.5 to 4.0 kW of thermal energy per meter of targeted heated length.
 22. The method of claim 15, wherein: the combustible fuel is a fuel gas; and the intensity of the first burner and the second burner are each controlled by adjusting a composition of the fuel gas.
 23. The method of claim 15, wherein the first burner and the second burner are sized to deliver 200 to 3,000 watts per meter of formation length desired to be heated.
 24. The method of claim 10, wherein a first portion of the tubing proximate the first combustion depth is constructed from an alloy or metal having a higher maximum working temperature than one or more other portions of the tubing.
 25. The method of claim 24, wherein the first portion of the tubing includes the tubing running from proximate the first combustion depth and extending down to proximate a tubing end.
 26. The method of claim 10, wherein a depth of the first burner, a rate of injecting the combustible fuel, a rate of injecting the oxidant, or combinations thereof, are specified so that a temperature of the flue gas traveling up the first annulus remains within about 300° C. to 750° C. across the selected portion of the organic-rich rock formation.
 27. The method of claim 26, wherein the rate of injecting the combustible fuel is reduced over time.
 28. The method of claim 10, further comprising: collecting the flue gas from the first annulus at a surface; compressing the collected flue gas; and mixing the compressed flue gas with compressed air containing oxygen to form an oxidant mixture.
 29. The method of claim 28, further comprising: injecting the oxidant mixture into the wellbore, the mixture forming at least a portion of the oxidant.
 30. The method of claim 10, further comprising: collecting the flue gas from the first annulus at a surface; compressing the collected flue gas; mixing the compressed flue gas with combustible gases to form a combustible fuel mixture; and delivering the combustible fuel mixture into the wellbore, the combustible fuel mixture forming at least a portion of the combustible fuel.
 31. The method of claim 10, further comprising: collecting the flue gas from the first annulus at a surface; and monitoring the collected flue gas for the presence of combustible species to assess whether the first burner is firing properly.
 32. The method of claim 31, wherein the combustible species comprise at least one of methane, ethane, hydrogen (H₂), and carbon monoxide.
 33. The method of claim 10, further comprising: monitoring a temperature of the flue gas at a point in the casing near the first combustion depth.
 34. The method of claim 10, wherein: the first tubular member has a lower end at the first combustion depth; the first burner is positioned at the lower end of the first tubular member; and the hardware further comprises a second tubular member residing within the tubing and having a lower end extending to the selected portion of the organic-rich rock formation at a second combustion depth lower than the first combustion depth, and a second burner positioned at the second combustion depth.
 35. The method of claim 34, wherein the hardware further comprises: a first tubular cowl disposed immediately below the first burner; and a second tubular cowl disposed immediately below the second burner.
 36. The method of claim 35, wherein the hardware further comprises: a third tubular member residing within the tubing and having a lower end extending to the selected portion of the organic-rich rock formation at a third combustion depth lower than the second combustion depth; a third burner positioned at the third combustion depth; a third tubular cowl disposed immediately below the third burner; and an insulation layer placed along an inner diameter of the tubing proximate the third burner.
 37. The method of claim 36, wherein: the first burner, the second burner, and the third burner are each separated by about 20 to 150 meters.
 38. The method of claim 35, wherein: the first burner and the second burner are separated by about 20 to 150 meters.
 39. The method of claim 10, wherein: the first burner is positioned along the first tubular member within the second annulus; and the hardware further comprises: a second burner positioned along the first tubular member within the second annulus at a second combustion depth within the selected portion of the organic-rich rock formation, the second combustion depth being below the first combustion depth.
 40. The method of claim 39, wherein: a first tubular cowl is disposed immediately below the first burner; and a second tubular cowl is disposed immediately below the second burner.
 41. The method of claim 40, wherein the hardware further comprises: a third burner positioned along the first tubular member within the second annulus at a third combustion depth within the selected portion of the organic-rich rock formation, the third combustion depth being below the second combustion depth; a third tubular cowl disposed immediately below the third burner.
 42. The method of claim 39, wherein the first burner and the second burner are separated by about 20 to 100 meters.
 43. The method of claim 10, wherein the first combustion depth is near the top of the selected section of the organic-rich rock formation.
 44. The method of claim 10, wherein the first burner is ignited using electric resistive heating elements.
 45. The method of claim 10, wherein the first burner is ignited using a removable electrical heated element which can be selectively inserted into a tubular member.
 46. The method of claim 10, wherein the first burner is ignited by injecting a pyrophoric substance into a tubular member.
 47. The method of claim 10, wherein the oxidant is injected at a mass rate of between greater than about 2.0 and about 6.0 times the stoichiometric combustion amount.
 48. The method of claim 10, wherein the oxidant is injected at a mass rate of between about 2.7 and about 5.4 times the stoichiometric combustion amount.
 49. The method of claim 10, wherein the oxidant is injected at a rate of about 5,000 to 50,000 kg/day.
 50. The method of claim 10, wherein the oxidant is injected at a rate of about 10,000 to 25,000 kg/day.
 51. The method of claim 10, further comprising: heating oil shale located in the oil shale formation in order to pyrolyze at least a portion of the oil shale into hydrocarbon fluids, the hydrocarbon fluids comprising gas; and producing the gas.
 52. The method of claim 51, wherein at least a portion of the combustible fuel is comprised of the gas.
 53. The method of claim 52, further comprising: treating the gas in order to substantially remove H₂S from the gas.
 54. The method of claim 3, wherein the oxidant is injected under a pressure of about 50 to 250 psia.
 55. The method of claim 3, wherein the combustible fuel is injected under a pressure of greater than about 200 psia.
 56. The method of claim 3, wherein the combustible fuel is natural gas that has been diluted with added inert components.
 57. The method of claim 56, wherein the added inert components comprise carbon dioxide (CO₂) or nitrogen (N₂).
 58. The method of claim 3, wherein the heat transfer coefficient between the down-flowing flue gas within the tubing and up-flowing flue gas in the first annulus is less than about 50 W/m² C on average below the first combustion depth.
 59. The method of claim 58, wherein the heat transfer coefficient between the downflowing flue gas within the tubing and the upflowing flue gas in the first annulus is about 25 W/m²C on average below the first combustion depth.
 60. The method of claim 3, further comprising: treating the flue gas at a surface to remove NO_(x) components; and venting the flue gas to the atmosphere.
 61. A heater well for in situ heating of an organic-rich rock formation, comprising: a casing in a wellbore located at least partially within the organic-rich rock formation, the casing extending to a depth within the organic-rich rock formation, the casing being substantially sealed to the organic-rich rock formation; a tubing within the casing, the tubing defining an annulus between the tubing and the surrounding casing; a first tubular member residing within the tubing and extending to a first depth within the organic-rich rock formation; a first burner proximate a bottom end of the first tubular member; a second tubular member residing within the tubing and extending to a second depth within the organic-rich rock formation that is lower than the first depth; a second burner proximate a bottom end of the second tubular member; and an insulation layer on the tubing proximate each of the first depth and the second depth; wherein thermal power capacities of the first and second burners, spacing between the first and second burners, lengths of the insulation layers, or combinations thereof are specified to create a substantially uniform temperature profile within the casing located along a selected portion of the organic-rich rock formation when the heater well is in operation; and wherein either an oxidant or a combustible fuel is injected at an excess mass flow rate greater than about 2.0 times a stoichiometric combustion flow rate, wherein the excess mass flow rate is selected to provide a more uniform temperature profile in the first annulus along the selected portion of the organic-rich rock formation.
 62. The heater well of claim 61, wherein the first and second burners are sized to deliver 200 to 3,000 watts per meter of formation length desired to be heated.
 63. The heater well of claim 61, further comprising: a first tubular cowl disposed immediately below the first burner; and a second tubular cowl disposed immediately below the second burner.
 64. The heater well of claim 63, further comprising: a third tubular member residing within the tubing and extending to a third depth within the organic-rich rock formation that is lower than the second depth; a third burner proximate a bottom end of the third tubular member; and a second insulation layer placed along the tubing proximate the third burner.
 65. A heater well for in situ heating of an organic-rich rock formation, comprising: a casing in a wellbore located at least partially within the organic-rich rock formation, the casing extending to a depth within or below the organic-rich rock formation, the casing being substantially sealed to the organic-rich rock formation; a tubing within the casing, the tubing defining a first annulus between the tubing and the surrounding casing; a tubular member residing within the tubing and extending at least to the organic-rich rock formation, the tubular member defining a second annulus between the tubular member and the surrounding tubing; a first burner positioned along the tubular member at a first depth within the second annulus and within the organic-rich rock formation; a second burner positioned along the tubular member at a second depth within the second annulus and within the organic-rich rock formation which is below the first depth; and an insulation layer on the tubing proximate each of the first depth and the second depth; wherein thermal power capacities of the first and second burners, spacing between the first and second burners, lengths of the insulation layers, or combinations thereof are specified to create a substantially uniform temperature profile within the casing located along a selected portion of the organic-rich rock formation when the heater well is in operation; and wherein either an oxidant or a combustible fuel is injected at an excess mass flow rate greater than about 2.0 times a stoichiometric combustion flow rate, wherein the excess mass flow rate is selected to provide a more uniform temperature profile in the first annulus along the selected portion of the organic-rich rock formation.
 66. The heater well of claim 65, further comprising: a first tubular cowl disposed immediately below the first burner; and a second tubular cowl disposed immediately below the second burner.
 67. The method of claim 66, further comprising: a third burner positioned along the tubular member at a third depth within the second annulus and within the organic-rich rock formation below the second depth; a third tubular cowl disposed immediately below the third burner; and an insulation layer placed along an inner surface of the tubing proximate the third burner.
 68. The method of claim 65, wherein the first burner and the second burner are sized to deliver 200 to 3,000 watts per meter of targeted heated length.
 69. A method of producing a hydrocarbon fluid, comprising: heating an organic-rich rock formation in situ using a heater well; and producing a hydrocarbon fluid from the organic-rich rock formation, the hydrocarbon fluid having been at least partially generated as a result of pyrolysis of formation hydrocarbons located in the organic-rich rock formation, wherein the heater well includes: a casing in a wellbore located at least partially within the organic-rich rock formation, the casing extending to a depth within the organic-rich rock formation, the casing being substantially sealed to the organic-rich rock formation; a tubing within the casing, the tubing defining an annulus between the tubing and the surrounding casing; a tubular member residing within the tubing and extending at least to the organic-rich rock formation; a first burner positioned along the tubular member at a first depth within the organic-rich rock formation; a second burner positioned along the tubular member at a second depth within the organic-rich rock formation which is below the first depth; and an insulative layer placed along the tubing adjacent at least the first and second burner; wherein thermal power capacities of the first and second burners, spacing between the first and second burners, lengths of the insulation layers, or combinations thereof are specified to create a substantially uniform temperature profile within the casing located along a selected portion of the organic-rich rock formation when the heater well is in operation; and wherein either an oxidant or a combustible fuel is injected at an excess mass flow rate greater than about 2.0 times a stoichiometric combustion flow rate, wherein the excess mass flow rate is selected to provide a more uniform temperature profile in the first annulus along the selected portion of the organic-rich rock formation. 